CO2 Sequestration In Reservoirs Research Articles

Characterization of petrophysical and seismic properties for CO2 storage with sensitivity analysis

Saline aquifers are considered as highly favored reservoirs for CO2 sequestration due to their favorable properties. Understanding the impact of saline aquifer properties on the migration and distribution of CO2 plume is crucial. This study focuses on four key parameters—permeability, porosity, formation pressure, and temperature—to characterize the reservoir and analyse the petrophysical and elastic response of CO2. First, we performed reservoir simulations to simulate CO2 saturation, using multiple sets of these four parameters to examine their significance on CO2 saturation and the plume migration speed. Subsequently, the effect of these parameters on the elastic properties is tested using rock physics theory. We established a relationship of compressional wave velocity (Vp) and quality factor (Qp) with the four key parameters, and conducted a sensitivity analysis to test their sensitivity to Vp and Qp. Finally, we utilized visco-acoustic wave equation simulated time-lapse seismic data based on the computed Vp and Qp models, and analysed the impact of CO2 saturation changes on seismic data. As for the above numerical simulations and analysis, we conducted sensitivity analysis using both homogeneous and heterogeneous models. Consistent results are found between homogeneous and heterogeneous models. The permeability is the most sensitive parameter to the CO2 saturation, while porosity emerges as the primary factor affecting both Qp and Vp. Both Qp and Vp increase with the porosity, which contradicts the observations in gas reservoirs. The seismic simulations highlight significant variations in the seismic response to different parameters. We provided analysis for these observations, which serves as a valuable reference for comprehensive CO2 integrity analysis, time-lapse monitoring, injection planning and site selection.

Exploring CO2 storage potential in Lithuanian deep saline aquifers using digital rock volumes: a machine learning guided approach

The increasing significance of carbon capture, utilization and storage (CCUS) as a climate mitigation strategy has underscored the importance of accurately evaluating subsurface reservoirs for CO2 sequestration. In this context, digital rock volumes, obtained through advanced imaging techniques such as micro-Xray computed tomography (MXCT), offer intricate insights into the porous and permeable structures of geological formations. This study presents a comprehensive methodology for assessing CO2 storage viability within Lithuanian deep saline aquifers, namely Syderiai and Vaskai, by utilizing petrophysical properties estimated from digital rock volumes of samples from analogous formations. It also demonstrates the potential of integrating advanced imaging techniques, machine learning, and numerical modeling for accurate assessment and effective management of subsurface CO2 storage.

Exploring CO2 storage potential in Lithuanian deep saline aquifers using digital rock volumes: a machine learning guided approach

The increasing significance of carbon capture, utilization and storage (CCUS) as a climate mitigation strategy has underscored the importance of accurately evaluating subsurface reservoirs for CO2 sequestration [1]. In this context, digital rock volumes, obtained through advanced imaging techniques such as micro-Xray computed tomography (MXCT), offer intricate insights into the porous and permeable structures of geological formations [2]. This study presents a comprehensive methodology for assessing CO2 storage viability within Lithuanian deep saline aquifers, namely Syderiai and Vaskai, by utilizing petrophysical properties estimated from digital rock volumes [3, 4]. These petrophysical properties were derived from core samples collected from these formations. Utilizing machine learning algorithms, porosity was estimated while the Lattice Boltzmann method (LBM) was applied to determine permeability [5]. The methodology employed for estimating these petrophysical parameters was initially validated using samples from formations analogous to Lithuanian formations. Subsequently, it was applied to rock samples specifically obtained from Lithuanian formations. The estimated petrophysical properties were compared with peer-reviewed data from published literature. When fluids such as CO2 or H2 are injected into sub-surface reservoirs, they can alter pore and grain characteristics. Therefore, it is crucial to extract representative element volumes (REVs) from segmented volumes to study the impact of fluids on porosity and their distribution [6]. These mini models, representing small portions of the larger formation, assist in predicting fluid flow within the formation, which is vital for assessing the efficiency and safety of carbon capture and storage (CCS) operations. Subsequently, numerical modelling was conducted using the petrophysical parameters as inputs to assess the storage capacity of the Lithuanian formations using tNavigator software [7]. This research contributes to an enhanced understanding of pore space distribution and its role in various aspects of long-term CO2 storage. It also demonstrates the potential of integrating advanced imaging techniques, machine learning, and numerical modeling for accurate assessment and effective management of subsurface CO2 storage. This study shall aid in enhanced understanding of pore space distribution and their contribution towards various aspects of long-term storage. The results can be extended to study the geochemical reactions and geo-mechanical behaviour of the rocks. Such studies shall further facilitate identification of reservoir(s) wherein sequestration potential can be reliably explored.

Coal microstructural and mechanical alterations induced by supercritical CO2 exposure: Role of water

Injection of CO2 into deep unminable coal reservoirs is regarded as an effective method to reduce greenhouse gas emissions. Coal seams with burial depth > 800 m are the potential reservoirs for CO2 sequestration, and CO2 is stored in the form of supercritical state. The interactions between supercritical CO2 (ScCO2) and coal are a complex process, which has influence on coal structures and strength. Recent studies are rarely reported regarding the impact of ScCO2-coal-water reactions on coal microstructures and mechanical strength. In this paper, comparative analysis was conducted on the microstructural changes and mechanical degradation of coal induced by ScCO2 treatment and ScCO2-water saturation. The results show that water has great influence on coal pore structure, functional groups, mineral compositions and mechanical properties during the reaction. ScCO2 saturation only triggers a small decline of 11.27–17.65% in aliphatic groups in coal, while approximately 62.75–85.92% of aliphatic groups are extracted by ScCO2-water. The largest hysteresis loops are found in samples saturated by ScCO2-water, followed by the specimens treated by ScCO2, illustrating that the complexity of coal pore structure is enhanced by ScCO2 interaction, and the presence of water can further increase the pore roughness. The UCS is reduced by < 13% after ScCO2 saturation on dry coal, but it is greatly decreased by 26.58–44.21% in the presence of water. In the process of interaction, water accelerates the hydrocarbon extraction and mineral dissolution to aggravate the degradation of coal strength. This work is conducive to understanding the process of CO2 geological sequestration.

Low-Temperature Adsorption Study of Carbon Dioxide on Porous Magnetite Nanospheres Iron Oxide

Porous magnetite Fe3O4 nano-spheres (PMNs) have been successfully produced and have been demonstrated to be high-efficiency adsorbents. The PMNs have a spherical shape with an average particle size of 25.84 nm. The BET surface area of PMNs is 143.65 m2g-1, with a total pore volume of 0.16 cm3g-1. As a result of CO2 adsorption and desorption features on dry PMNs, this synthesized material is projected to be exploited as possible CO2 sequestration reservoirs to minimize greenhouse gas emissions. CO2 adsorption was best at low temperatures and with dry PMNs. PMNs, on the other hand, has a very high adsorption capacity of 0.96 mmol/g. According to the IUPAC categorization of adsorption isotherms, all CO2 adsorption isotherms of coal samples fall into type I, which most likely indicates adsorption restricted to a few layers of molecules (micropores and mesopores). Langmuir, Henry, Dubbin, Temkin, Toth, Harkin-Jura, Elovich, Redlich Peterson, and Josene models suit any experimental adsorption data that best predict the heterogeneous surface features of PMNs.

Description, Kinetic and Equilibrium Studies of the Adsorption of Carbon Dioxide in Mesoporous Iron Oxide Nanospheres

Mesoporous iron oxide nanospheres (MINs) have been successfully synthesized and have proven to be high-efficiency adsorbents. The morphology of the MINs is very uniform in spherical form, with an average particle size of 23-27 nm in the diameter range. MINs content has a fairly high BET surface area of 188.25 m2g−1 and a total volume of 0.14 cm3g−1 pores. Thus, seams were seen as potential CO2 sequestration reservoirs to reduce greenhouse gas emissions. The CO2 adsorption was favorable at low temperature and dry MINs conditions. However, MINs have a high adsorption capacity of 0.15 mmol/g. The CO2 adsorption isotherm of all coal samples according to the IUPAC classification of adsorption isotherms fits category I, which most likely explains adsorption confined to a few layers of molecules (micropores and mesopores). The balancing assessment using Langmuir, Henry, Dubbin, Temkin, Toth, Harkins-Jura, Elovich, Redlich-Peterson, and Josene model provided the best fit for any experimental adsorption data that predict heterogeneous surface properties of MINs.

Core-scale investigation of the effect of heterogeneity on the dynamics of residual and dissolution trapping of carbon dioxide

Geologic heterogeneity, which commonly exists in target reservoirs for CO2 sequestration, has a significant effect on CO2 trapping. In this study, we performed Darcy-scale multiphase flow experiments on a heterogeneous rock with in-situ imaging techniques to obtain X-ray images of CO2 saturation during both drainage and imbibition. Residual trapping was assessed using the initial-residual characteristic curve. The distribution of residual CO2 saturation widened as the initial saturation increased, implying that the capillary heterogeneity becomes increasingly important with higher initial CO2 saturation. During dissolution, we discovered new flow regimes in heterogeneous media and proposed a quantitative scaling relationship for their temporal evolution. The high-porosity layers showed a descending slope of ~0.4 during the early stage of dissolution, whereas it decreased by an order of magnitude (slope ~ 0.04) during the later stage. The high-capillarity layers, however, showed a single descending trend during dissolution. The highly time-resolved images of CO2 saturation provide a detailed understanding of the dynamic processes of both residual and dissolution trapping in heterogeneous media, which contributes to a wide range of applications, including environmental remediation, CO2 sequestration, and the enhancement of energy resources from hydrocarbon reservoirs.

Sedimentology, diagenesis, and reservoir characterization of the Permian White Rim Sandstone, southern Utah: Implications for carbon capture and sequestration potential

Rising CO2 emissions have caused scientists and policy makers to explore potential solutions to reduce atmospheric CO2 levels, including carbon capture and sequestration. This project, funded through the Department of Energy CarbonSAFE initiative, aims to characterize the potential storage capacity and preferential fluid-flow pathways through the Permian White Rim Sandstone on and near the San Rafael Swell, Utah, to assess the formation’s viability as a possible CO2 sequestration reservoir. A diverse suite of sedimentological observations and diagenetic analyses was used to assess the White Rim Sandstone’s reservoir potential, including detailed outcrop observations, facies descriptions and ichnology, measured stratigraphic sections with associated correlations, permeability measurements, thin-section petrography, and visible and near-infrared spectroscopy. Stratigraphically, the White Rim Sandstone has two major units separated by a marine transgressive surface. The lower eolian unit is characterized by decimeter- to meter-scale trough cross-bedded grain-flow and wind-ripple facies. The upper reworked, shallow-marine unit has a consistent set of facies at all three field sites: (1) soft-sediment deformation facies (e.g., contorted bedding or clastic pipes), (2) symmetric ripple laminations, (3) bioturbated (dominantly horizontal), and (4) bioturbated (dominantly vertical). This set of four facies represents the transgression of the Permian Kaibab sea over the Permian White Rim coastal dune field. The outcrop samples and subsurface core samples (∼1561–2243 m deep and ∼33–50 km away from the outcrop localities) experienced different diagenetic fluid-flow histories that drastically impacted the reservoir properties. Outcrop samples have initial quartz overgrowth cements followed by rim-forming calcite cements, iron oxide cements, and occasional oil staining. In contrast, the core samples show significant compaction, followed by quartz overgrowth cementation and a later stage of patchy, large, pore-filling calcite cement that eliminated the porosity and permeability of the potential reservoir (<0.1 md). Outcrop permeability values tend to reflect textural differences in facies, particularly the presence and spacing of internal laminations and bounding surfaces. Facies with fewer internal laminations, such as the grain-flow facies, have higher permeability values than facies with closely spaced internal laminae, such as the wind-ripple facies. Disruption of original bedding (e.g., soft-sediment deformation or bioturbation) alters original depositional textures and creates preferential flow pathways with the potential to increase permeability. Overall, if the diagenesis and resulting low permeability values of the core samples are representative of the White Rim Sandstone at depth, then the White Rim Sandstone would not make a high-quality storage reservoir despite initial, promising outcrop results.

Facies and depositional environments of the Upper Muschelkalk (Schinznach Formation, Middle Triassic) in northern Switzerland

Subsurface sedimentary strata in northern Switzerland, such as the Middle Triassic Upper Muschelkalk, are attracting interest as potential reservoirs for CO2 sequestration and for geothermal energy production. Characterizing facies in such strata aids prediction of reservoir properties in unexplored areas. Although well studied elsewhere, the Swiss Upper Muschelkalk has received little attention despite containing the southern-most deposits of the Central European Basin. The Upper Muschelkalk represents the deposits of a storm-dominated, homoclinal carbonate ramp, developed during a basin-wide 3rd-order transgressive–regressive cycle. Our facies analyses of nine boreholes across northern Switzerland reveal 12 lithofacies, eight lithofacies associations and four types of metre-scale 5th-order cycles corresponding to at least 23 short orbital eccentricity cycles. During the 3rd-order transgression, crinoidal bioherms developed across Switzerland followed by deep-ramp environments. Subsequently, tempestites were deposited up to and after the basin-wide maximum flooding surface. Lateral tempestite correlations indicate that Switzerland lay within an open-marine, mid-ramp environment during almost half of the depositional history. Mid-ramp deposits pass upwards to prograding shelly shoals, which sheltered a back-shoal lagoon containing patchy oolitic shoals. At the top of the Upper Muschelkalk, back-shoal sediments give way to coastal sabkha facies, which were overlain by oolitic shoals during a marine transgression. Shortly thereafter the top of the Upper Muschelkalk was dolomitized by brines from an overlying hypersaline environment that was later removed by a basin-wide erosive event. Overall, the paucity of porous shoal facies, unlike in southern Germany, has resulted in poor primary reservoir properties in the Upper Muschelkalk of Switzerland.

Forecasting commercial-scale CO2 storage capacity in deep saline reservoirs: Case study of Buzzard's bench, Central Utah

Successful implementation of Geological Carbon Sequestration (GCS) projects requires long-term storage capacity and security at selected fields. The purpose of this work is to evaluate and quantify potential storage capacity, trapping mechanisms and potential risks associated with commercial-scale (at least 50 MT CO2) injection and storage of CO2 in the subsurface. The specific case study evaluated is the Navajo Sandstone formation, a target GCS reservoir in Buzzard's Bench, Central Utah. Two-dimensional reactive transport models are designed for 1000-year simulations, with 50 MT CO2 injection. An uncertainty analysis with different reservoir porosity and permeability are conducted, because only a few samples of the reservoir and caprock near the proposed reservoir were collected. Specific objectives include forecasting the extent of an injected CO2 plume, competing roles of different trapping mechanisms, trapping capacity changes due to porosity changes, and forecasts of CO2 migration into adjacent caprock (the Carmel formation in this case). Resultssuggest that the Navajo formation may be a reliable CO2 sequestration reservoir, capable of trapping commercial volumes. The Jurassic Kayenta and Wingate formations may also store some injected CO2, with these and other clastic formations forming a “stacked storage” system. Storage efficiency decreases with distance away from an injection well, and the estimated storage efficiency for the case study simulations (Navajo storage only) are 2.3 ± 1% within the area of review (AoR) calculated by National Risk Assessment Partnership (NRAP) toolset. After 1000 years, about half of the injected CO2 may be sequestered in safe phases including residually-trapped CO2 via surface tension, aqueous and mineral phases. A small amount of total injected CO2 (∼3%) tends to migrate into the caprock, but is mostly stored in the sandstone reservoir. Simulated porosity enhancement caused by mineral alteration is negligible within 1000 years of the start of injection, with only ∼0.6% added to the total pore volume by the end of simulations. Future studies of detailed reservoir and caprock characteristics with in-situ samples may be helpful for further determining reservoir sequestration capacity and reliability.

A novel CO2 and pressure responsive viscoelastic surfactant fluid for fracturing

Hydraulic fracturing is playing a more and more important role in rapid shale oil and gas recovery development. Meanwhile, damage to the reservoir fracture and environmental contamination caused by fracturing fluid flowback water has raised serious concerns. In this study, a CO2-responsive surfactant, erucamidopropyl dimethylamine (EA), was synthesized and used as the thickening agent to develop a novel viscoelastic surfactant (VES)-based fracturing fluid. This fluid was responsive to the presence and pressure of CO2. It was not only rock formation friendly and environment benign but also readily reusable attributed to a gelling-breaking process that can be easily controlled by manipulating CO2 gas conditions. The viscoelastic behaviors of this VES fluid were investigated through rheological measurements under ambient and elevated temperature and pressure. The fluid-rock interaction was studied in core flooding tests. Results showed a good CO2-responsiveness, switchable viscoelastic performance, high shear tolerance, thermal stability, good salinity tolerance, and low core damage of the fluid. The switchable rheological behavior implies this fracturing fluid can readily be reused. It is expected that this fluid finds applications not only in enhanced oil and gas recovery, but also in other areas such as CO2 sequestration reservoir leakage sealing.

Lattice Boltzmann simulation of dissolution-induced changes in permeability and porosity in 3D CO2 reactive transport

Dissolution and precipitation of rock matrix are one of the most important processes of geological CO2 sequestration in reservoirs. They change connections of pore channels and properties of matrix, such as bulk density, microporosity and hydraulic conductivity. This study builds on a recently developed multi-layer model to account for dynamic changes of microporous matrix that can accurately predict variations in hydraulic properties and reaction rates due to dynamic changes in matrix porosity and pore connectivity. We apply the model to simulate the dissolution and precipitation processes of rock matrix in heterogeneous porous media to quantify (1) the effect of the reaction rate on dissolution and matrix porosity, (2) the effect of microporous matrix diffusion on the overall effective diffusion and (3) the effect of heterogeneity on hydraulic conductivity. The results show the CO2 storage influenced by factors including the matrix porosity change, reaction front movement, velocity and initial properties. We also simulated dissolution-induced permeability enhancement as well as effects of initial porosity heterogeneity. The matrix with very low permeability, which can be unresolved on X-ray CT, do contribute to flow patterns and dispersion. The concentration of reactant H+ increases along the main fracture paths where the flow velocity increases. The product Ca++ shows the inversed distribution pattern against the H+ concentration. This demonstrates the capability of this model to investigate the complex CO2 reactive transport in real 3D heterogeneous porous media.

Adsorption kinetics and diffusion modeling of CH4 and CO2 in Indian shales

The concept of increased gas (methane) recovery with simultaneous CO2 sequestration in unconventional reservoirs like gas shales has been studied in the past few years. Diffusion is the main transport mechanism in shale gas reservoir. Understanding the methane and CO2 diffusion properties of shales and its modeling is important for planning successful methane recovery and CO2 sequestration in these reservoirs. Methane and CO2 adsorption kinetic studies were carried out at four different pressure steps (in the range of 3.5–8.9 MPa for CH4 and 2–6 MPa for CO2) to investigate their diffusion behavior on two shale samples (Pakur and Salanpur) from Damodar Valley Basin, India. The sorption kinetic data was modeled using unipore model and modified unipore model (MM). The unipore model is giving good match with experimental sorption kinetics data up to a fractional uptake of 62–92% for methane and 62–88% for CO2. The MM model is giving very good match up to the fractional uptake of 78–99% for methane and 77–98% for CO2. It was observed that the MM model is giving better fit than that of unipore model for both gases for the entire pressure range. Thus it can be suggested that MM model is a better model to represent the diffusion of methane and CO2 in shales.

Chemical degradation of reinforced epoxy‐cement composites under CO2‐rich environments

Long‐term wellbore integrity is crucial to prevent leakage of CO2 and to ensure performance and safety of carbon geologic storage. One of the concerns is the degradation of Portland cement due to its exposure to CO2. In this study, Portland cement paste composed of three reinforced‐epoxy resins (talc, agalmatolite, and montmorillonite clay as filler) was compared to unmodified cement paste with respect to CO2 resistance. CO2 degradation experiments were conducted with aqueous CO2 at elevated pressure (50 bar) and temperature (70°C) in order to mimic wellbore conditions. Epoxy cement composites were characterized by phenolphthalein test, field emission scanning electron microscopy, Fourier transform infrared spectroscopy, and mechanical compression test. The preparation method of the composites is the parameter likely to affect the CO2 resistance than curing conditions (natural and thermal). Addition of up to 5% of montmorillonite clay reinforced‐epoxy resins provides an improvement in CO2 resistance over unmodified Portland cement paste, showing to be a promising alternative to obtain suitable materials for use in wellbores in CO2 sequestration reservoirs. POLYM. COMPOS., 39:E2234–E2244, 2018. © 2017 Society of Plastics Engineers

Microscopic diffusion of CO2 in clay nanopores

Natural gas production from shale in recent years has made a significant impact on the energy sector. It also presents potential opportunities to mitigate global warming by using shale reservoirs for CO2 sequestration. We attempt to understand the microscopic impact of shale on CO2 transport. We utilize equilibrium molecular dynamics (MD) to study the diffusion behavior of CO2 in the clay part of shales. Such microscopic examination can connect micro-scale calculations to macro-scale measurements. Results show that confinement has profound effects on CO2 diffusion. The diffusion coefficient was found to be slightly anisotropic due to the nature of the clay surface.

A multiscale model of distributed fracture and permeability in solids in all-round compression

We present a microstructural model of permeability in fractured solids, where the fractures are described in terms of recursive families of parallel, equidistant cohesive faults. Faults originate upon the attainment of tensile or shear strength in the undamaged material. Secondary faults may form in a hierarchical organization, creating a complex network of connected fractures that modify the permeability of the solid. The undamaged solid may possess initial porosity and permeability. The particular geometry of the superposed micro-faults lends itself to an explicit analytical quantification of the porosity and permeability of the damaged material. The model is the finite kinematics version of a recently proposed porous material model, applied with success to the simulation of laboratory tests and excavation problems [De Bellis, M. L., Della Vecchia, G., Ortiz, M., Pandolfi, A., 2016. A linearized porous brittle damage material model with distributed frictional-cohesive faults. Engineering Geology 215, 10–24. Cited By 0. 10.1016/j.enggeo.2016.10.010]. The extension adds over and above the linearized kinematics version for problems characterized by large deformations localized in narrow zones, while the remainder of the solid undergoes small deformations, as typically observed in soil and rock mechanics problems. The approach is particularly appealing as a means of modeling a wide scope of engineering problems, ranging from the prevention of water or gas outburst into underground mines, to the prediction of the integrity of reservoirs for CO2 sequestration or hazardous waste storage, to hydraulic fracturing processes.

Capacity and suitability assessment of deep saline aquifers for CO2 sequestration in the Bohai Bay Basin, East China

CO2 sequestration in deep saline aquifers has proven to be one of the most promising options to reduce anthropogenic CO2 emissions. Sedimentary basins are chosen as targets of CO2 sequestration due to the existence of deep saline aquifers. This paper presents the first systematic investigation on the occurrence and characteristics of potential reservoirs for CO2 sequestration in deep saline aquifers in the Bohai Bay Basin (BBB) and offers detailed estimates on the storage capacity within the depth range from 800 to 3500 m. A preliminary suitability assessment for preferential sites is also presented. Geological analyses show that deep saline aquifers in Guantao formation (Ng) of Neogene, Dongying (Ed) and Shahejie formations (Es1, Es2, Es3, Es4) of Paleogene are potential reservoirs. Deep saline aquifers in the BBB may accommodate about 3922 Mt CO2 with 50 % confidence level, according to a modified CSLF (Carbon Sequestration Leadership Forum) method. The CO2 storage capacity of individual depression varies from 65 Mt (Liaohe depression) to 934 Mt (Liaodongwan-Bozhong depression). The Guantao formation (Ng) of Neogene is a regionally distributed reservoir with low TDS (Total Dissolved Solids) and favorable depth and thickness, the capacity of which accounts for 84 % of the total and is therefore considered as the most promising reservoir. Preliminary suitability assessment is carried out in terms of sedimentology, tectonic stability, geothermal conditions, saline water characteristics, potentially conflicting resources development as well as CO2 emission sources. The Liaodongwan & Bozhong, Jiyang & Changwei and Huanghua depressions are chosen as the most suitable sites for CO2 storage. Jizhong and Liaohe depressions are less suitable while Linqing depression is not suitable due to its lower tectonic stability, geological information and CO2 emission sources. Although uncertainties exist, the estimate in this study is significant for future study and implementation of CO2 sequestration in the basin.

Evaluating fractures in rocks from geothermal reservoirs using resistivity at different frequencies

One of the key issues to a successful EGS (Enhanced or engineered Geothermal System) is the creation of a great density of fractures. The detection and characterization of the created fractures is crucial in evaluating the geothermal energy resources in such EGS projects as well as in reservoirs for CO2 sequestration and storage. Methods to evaluate the fractures after stimulations are few, and limited in application. To this end, an approach to detecting and evaluating the fractures using resistivity data measured at different frequencies was developed in this study. The effects of fractures on resistivity measurements at different frequencies have been investigated as a function of water saturation in rocks with different porosity, permeability and lithology. Different rocks (Berea sandstone, and greywacke from The Geysers geothermal reservoir) were used in this study. The permeability of the samples ranged from 0.5 to over 1000 md for the matrix. The frequency ranged from 100 to 100,000 Hz. It was found that the effect of frequency on resistivity is different in rocks with and without fractures, especially in the range of low water saturation. The validity of the Archie equation depends on the existence of fractures, the frequency, and the range of water saturation. The relationship between resistivity and water saturation did not follow the Archie equation at low water saturation in some rocks with fractures. Models for characterizing different types of rocks with specific fracture patterns have been established using the resistivity data measured at different frequencies and different water saturations.

Variations in mineralization potential for CO2 related to sedimentary facies and burial depth – a comparative study from the North Sea

Abstract In evaluating storage security in geological reservoirs for CO2 sequestration, the relative effect of trapping mechanisms is essential. In this study two reservoir candidates offshore western Norway are compared with respect to variation in residual-, dissolution- and subsequently mineralization potential. The Sognefjord and Johansen formations represent depositional analogues with comparable petrographical composition. The potential reservoirs are located at different burial depths; 1.3 and 3 km respectively. Testing the reactivity (i.e. fluid flow- and geochemical modeling) in two different geological settings within each reservoir, the dissolution potential was found to be larger in the shallow, most porous case due to extensive plume migration In contrast mineral trapping proved most efficient in the deeper, high temperature cases. Mineralization potentials also varied between different sedimentary facies in both reservoir candidates.

Fracture Propagation Driven by Fluid Outflow from a Low-Permeability Aquifer

Deep saline aquifers are promising geological reservoirs for CO2 sequestration if they do not leak. The absence of leakage is provided by the caprock integrity. However, CO2 injection operations may change the geomechanical stresses and cause fracturing of the caprock. We present a model for the propagation of a fracture in the caprock driven by the outflow of fluid from a low-permeability aquifer. We show that to describe the fracture propagation, it is necessary to solve the pressure diffusion problem in the aquifer. We solve the problem numerically for the two-dimensional domain and show that, after a relatively short time, the solution is close to that of one-dimensional problem, which can be solved analytically. We use the relations derived in the hydraulic fracture literature to relate the the width of the fracture to its length and the flux into it, which allows us to obtain an analytical expression for the fracture length as a function of time. Using these results we predict the propagation of a hypothetical fracture at the In Salah CO2 injection site to be as fast as a typical hydraulic fracture. We also show that the hydrostatic and geostatic effects cause the increase of the driving force for the fracture propagation and, therefore, our solution serves as an estimate from below. Numerical estimates show that if a fracture appears, it is likely that it will become a pathway for CO2 leakage.