Search

Introduction: Carbon dioxide (CO2) enhanced gas recovery represents a viable strategy for sequestering CO2 while concurrently augmenting gas production from subsurface reservoirs. Gas reservoirs, as inherent geological formations, are optimal repositories for gaseous compounds, rendering them suitable for CO2 storage. Nevertheless, the economic viability of pure CO2 storage necessitates integration with oil and gas recovery mechanisms to facilitate widespread CO2 utilization. Method: This study addresses the complexities of CO2 enhanced gas recovery through a comprehensive approach that combines theoretical model and numerical simulations. A numerical model is developed to simulate three-component diffusion involving CO2, and methane (CH4) in a two-phase system comprising gas and water. Results: The investigation systematically explores the process of enhanced CH4 extraction and CO2 injection into the reservoir and examines the influencing factors on extraction. Simulation results reveal a power-law decrease in CH4 production rate, stabilizing at a constant extraction rate. Enhanced CH4 extraction benefits from increased porosity, with higher porosity levels leading to greater CH4 extraction. Permeability augmentation positively influences CH4 production, although with diminishing returns beyond a certain threshold. The CO2 injection rate shows a direct proportionality to CH4 production. However, elevated CO2 injection rates may increase reservoir pressure, potentially causing cap rock damage and CO2 gas flushing. Discussion: This study contributes valuable theoretical insights to the field of CO2 enhanced gas recovery engineering, shedding light on the intricate dynamics of multi-component fluid transport processes and their implications for sustainable CO2 utilization. [ABSTRACT FROM AUTHOR]

The smectite-illite transition in shales due to subsidence, temperature changes and diagenesis influences many processes in a sedimentary basin that can contribute to overpressure build up like reducing the shale permeability. The smectite-rich layers can form sealing barriers to fluid flows that will influence pore pressure prognosis for drilling campaigns, contribute to sealing caprocks for possible CO2 storage and to sealing of plugging and abandonment wells. In this work, we have included the diagenetic smectite-illite transition into a three-dimensional pressure simulation model to simulate its effect on pressure build-up due to reduced shale permeabilities over geological time scale. We have also tested effect of thermal history and potassium concentration on the process of smectite-illite transition and the associated smectite-illite correction on permeability. A new smectite-illite correction has been introduced, to mimic how shale permeability will vary dependent on the smectite-illite transition. Stochastic Monte Carlo simulations have been carried out to test the sensitivity of the new correction parameters. Finally, a 3D Monte Carlo pore pressure simulation with 1000 drawings has been carried out on a case study covering Skarv Field, and Dønna Terrace offshore Mid-Norway. The simulated mean overpressures are in range with observed overpressures from exploration wells in the area for the Cretaceous sandy Lysing Formation and for the two Cretaceous Intra Lange Formation sandstones. The simulated smectite content versus depth is in line with published XRD dataset from wells. The corresponding modelled present-day permeabilities for the shales including the smectite-illite transition are two magnitudes higher than measured permeabilities on small samples in the laboratory using transient decay method. The measured permeabilities are in the range of 2.66·10-18 to 3.94·10-22 m² (2695 to 0.39 nD) for the North Sea database and represent the end members for shales-permeabilities with the lowest values, since the small samples are selected with no or minor natural fractures. This work shows that by upscaling shale permeabilities from mm-scale to km scale, natural fractures and sedimentary heterogeneities will increase the shale permeabilities with a factor of two and that by including permeability correction controlled by the smectite fraction, pressure ramp can be simulated due to diagenesis effect in shales. [ABSTRACT FROM AUTHOR]

Gas reservoirs have significant engineering characteristics of injection and extraction. The reservoir cap rock is subjected to cyclic alternating loading and has the potential risk of seal failure. Therefore, it is necessary to study the stress−percolation−damage mechanism of the reservoir cap rock in depleted gas reservoirs. The rock Mechanics Test System (MTS) was used to study the permeability characteristics of a typical mud shale cap layer under different loading and unloading rates, analyze the deformation characteristics and permeability performance evolution law of the rock under the confining pressure alternation, and study the effects of loading and unloading rate, confining pressure and number of cycles on the permeability of the cap rock. The test results show that with the increase in the number of cycles, the hysteresis loop moves in the direction of axial strain increase offset. The overall morphology is presented as an elongated type, and the damage of the specimen is small in the cyclic confining pressure; At the beginning of the cycling period, the permeability decreases with the increase in the confining pressure in the form of a negative exponential. At the later stage of the cycling period, the permeability basically stays unchanged, and is maintained at a low level; At low confining pressure, permeability also decreases in a negative exponential form with the increase in the number of confining pressure cycles; The greater the loading and unloading rate at the beginning of the cycle, the more the permeability decreases; There is a tendency of sealing improvement under cyclic loading in the gas storage of depleted reservoirs with mud shale as the cap layer. The results of the study can provide technical parameters for the evaluation of the cap sealing of gas storage of depleted reservoirs. [ABSTRACT FROM AUTHOR]

Copyright of Iraqi Journal of Chemical & Petroleum Engineering is the property of Republic of Iraq Ministry of Higher Education & Scientific Research (MOHESR) and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Carbon dioxide (CO2) dissolution is the secondary trapping mechanism enhancing the long-term security of CO2 in confined geological formations. CO2 injected into a randomly multilayered formation will preferentially migrate along high permeability layers, increasing CO2 dissolution efficiency. In this study, sequential Gaussian simulation is adopted to construct the stratified saline formations, and two-phase flow based on MRST is established to illustrate the spatial mobility and distribution of CO2 migration. The results show that gravity index G and permeability heterogeneity σ Y 2 are the two predominant factors controlling the spatial mobility and distribution of CO2 transports. The CO2 migration shows a totally different spatial mobility under different gravity index and heterogeneity. When the permeability discrepancy is relatively larger, CO2 preferentially migrates along the horizontal layer without accompanying the vertical migration. For the formation controlled by gravity index, CO2 migration is governed by supercritical gaseous characteristics. For the medium gravity index, the upward and lateral flow characteristics of the CO2 plume is determined by gravity index and heterogeneity. When the gravity index is smaller, permeability heterogeneity is the key factor influencing CO2 plume characteristics. Permeability heterogeneity is the decisive factor in determining final CO2 dissolution efficiency. This investigation of CO2 mobility in randomly multilayered reservoirs provides an effective reference for CO2 storage. [ABSTRACT FROM AUTHOR]

Copyright of Petroleum Geology & Recovery Efficiency is the property of Petroleum Geology & Recovery Efficiency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

• Sealing mechanism of ultra-high T/P CO2-rich reservoirs analyzed in the South China Sea. • Hydraulic failure occurred after the capillary failure. • Capillary leakage is not effectively reducing reservoir pressure. Global industry drillings targeted at deep-burial hydrocarbons have renewed the record of maximum sustainable overpressure in sedimentary basins. However, the influence of extremely high overpressure on natural fluid accumulation and artificial waste sequestration is not yet completely understood. To better understand the motion characteristics of the highly overpressured CO 2 -rich fluid, the CO 2 retention capacity was quantified, and the CO 2 -rich fluid motion trails were evaluated in an ideal natural laboratory in the Yinggehai Basin. The hydraulic sealing capacity was higher than the capillary sealing capacity in the highly overpressured stratum. Relative to the situations of no breach or solely breached by capillary failure, the superposition of capillary and hydraulic failures resulted in the caprock integrity breakage by faults (or fractures), diapirs, and pipes. Meanwhile, the high expulsion flux of CO 2 -rich fluid caused the consumption of chlorite to generate illite in the caprock of dual-breached fields. The CO 2 -rich fluid flux of capillary invasion was limited by the inherently low permeability of caprock, which may be insufficient for a dramatic change of hydrogen ions or electron activities to induce remarkable chlorite dissolution in the caprock of the sole-breached field. [ABSTRACT FROM AUTHOR]

Absence of a permeability log necessary to assess reservoir quality and injectivity for potential CO2 storage in the heterogeneous and complex South Georgia Rift (SGR) basin provides the motivation for this study. The focus of this study was on the Triassic-Jurassic red beds buried, entrenched beneath the Cretaceous-Cenozoic Coastal Plain sediments. Moreover, the significant cost typically between $10 M and $100 M associated with drilling and logging for in situ permeability coupled with the limited resolution of existing core data further makes this work necessary. The purpose is to relate, use the interpretation of the predicted permeability distribution to assess feasibility for safe and long-term CO2 sequestration. This study also intends to establish the impacts of active and passive tectonism that has shaped and/or re-shaped the evolution of the basin on the present-day permeability. A methodology was applied that utilizes the pore space and geohydraulic properties of the reservoir from existing laboratory and well data to produce a newly derived permeability log. It shows a non-uniform distribution with depths possibly due to geologic changes in the confined and heterogeneous red beds. The derived log displays characteristics consistent with observations from the porosity and resistivity logs. The interpretation of these logs provides evidence for the presence of low permeable, tightly cemented, and compacted red beds. We conclude that the low permeability aided by the low resistivity depicted in the red beds suggests increased confining stress and reduced injectivity, and that the uncharacteristically low permeability reflects a deformed basin shaped with episodes of uplift and erosion. [ABSTRACT FROM AUTHOR]

This study evaluates the chemo-mechanical influence of injected CO2 on the Morrow B sandstone reservoir and the upper Morrow shale caprock utilizing data from the inverted 5-spot pattern centered on Well 13-10A within the Farnsworth unit (FWU). This study also seeks to evaluate the integrity of the caprock and the long-term CO2 storage capability of the FWU. The inverted 5-spot pattern was extracted from the field-scale model and tuned with the available field observed data before the modeling work. Two coupled numerical simulation models were utilized to continue the study. First, a coupled hydro-geochemical model was constructed to simulate the dissolution and precipitation of formation minerals by modeling three intra-aqueous and six mineral reactions. In addition, a coupled hydro-geomechanical model was constructed and employed to study the effects of stress changes on the caprock's porosity, permeability, and ground displacement. The Mohr–Coulomb circle and failure envelope were used to determine caprock failure. In this work, the CO2-WAG injection is followed by the historical field-observed strategy. During the forecasting period, a Water Alternating Gas (WAG) injection ratio of 1:3 was utilized with a baseline bottom-hole pressure constraint of 5500 psi for 20 years. A post-injection period of 1000 years was simulated to monitor the CO2 plume and its effects on the CO2 storage reservoir and caprock integrity. The simulation results indicated that the impacts of the geochemical reactions on the porosity of the caprock were insignificant as it experienced a decrease of about 0.0003% at the end of the 1000-year post-injection monitoring. On the other hand, the maximum stress-induced porosity change was about a 1.4% increase, resulting in about 4% in permeability change. It was estimated that about 3.3% of the sequestered CO2 in the formation interacted with the caprock. Despite these petrophysical property alterations and CO2 interactions in the caprock, the caprock still maintained its elastic properties and was determined to be far from its failure. [ABSTRACT FROM AUTHOR]

The increasing carbon dioxide content is identified as the main cause of global warming. Capturing carbon dioxide in the atmosphere and transporting it to deep salt layer for storage have been proven and practiced in many aspects, which considered to be an effective way to reduce the content of carbon dioxide in the atmosphere. The sealing property of cap rocks is one of the key factors to determine whether CO2 can be effectively stored for a long time. In view of the disadvantages of tedious and time-consuming laboratory test methods for breakthrough pressure of cap rock, this paper explores the relationship between breakthrough pressure and other parameters such as porosity, permeability, density, specific surface area, maximum throat radius, and total organic carbon. The results show that the rock breakthrough pressure is closely related to the maximum throat radius and permeability determined by the mercury injection method, followed by the porosity and specific surface area, and less related to the density, depth, and TOC content of the rock itself. Then, with the selected parameters, a neural network model is established to predict the breakthrough pressure of cap rock, which can achieve good prediction results. [ABSTRACT FROM AUTHOR]

We aimed to evaluate various factors that control the frictional and transport properties of gouge-filled faults cutting carbonate-bearing shales or claystone formations. The research experimentally determined the effect of shear displacement, dynamic shearing, static holding, and effective normal stress on fault gouge permeability, both parallel and perpendicular to the fault boundaries, as well as on frictional behaviour. The simulated gouge was prepared from crushed Opalinus Claystone (OPA), on which we performed direct shear experiments. The direct-shear experiments (σ푛 푒ƒƒ = 5 - 50 MPa, 푃ƒ = 2 MPa, and 푇 ˜ 20°C) showed ~1 order of magnitude decrease in permeability with shear displacement (up to ~6 mm), for both alongand across-fault fluid flow orientation. Moreover, our data showed an initial, pre-shear permeability anisotropy of up to ~1 order of magnitude, which decreased with increasing shear displacement (maturity) to ~0.5, with the along-fault permeability being consistently higher. Our results have important implications for calcite-rich claystones and shale formations, and in particular any pre-existing faults therein, that seal hydrocarbon reservoirs and potential CO2 storage reservoirs, as the current results point to a higher leakage potential of pre-existing faults compared to the intact caprock. [ABSTRACT FROM AUTHOR]

Copyright of Petroleum Geology & Recovery Efficiency is the property of Petroleum Geology & Recovery Efficiency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Geological carbon capture and storage (CCS) is a critical technology for mitigating greenhouse gas emissions, but the risk of leakage remains a significant concern. Fault and fracture networks across sealing intervals are potential pathways for CO 2 to escape from storage reservoirs, necessitating accurate assessment of their permeability and connectivity. Our study presents an integrated approach for modelling geological leakage in fault zones, combining single fracture stress-permeability laboratory measurements with detailed fracture outcrop data to simulate in-situ conditions for carbon storage. We studied caprock sequences cut by a normal fault in the Konusdalen West area (Svalbard, Norway), a regional seal for the reservoir of the Longyearbyen CO 2 Laboratory, and an analogue to Barents and North seas caprock formations. Digitising the outcropping fracture network, we explored the variations in fracture size distribution and their connectivity in different portions of the fault zone. These parameters are fundamental to establish if the fracture network provides permeable pathways. Integrating outcrop analysis with laboratory measurements allows us to create coupled hydromechanical models of the natural fracture network and to evaluate their upscaled permeability. We found that fracture network geometries vary across the fault zone, resulting in different upscaled permeability models, thus highlighting the importance of including detailed fracture network information into permeability simulations. Our study provides a framework for incorporating fracture permeability measurements and outcrop analysis into the modelling of geological leakage in fault zones, which can inform the design and operation of CCS projects and help mitigate the risks associated with geological storage of CO 2. • Integrated CO 2 leakage modelling in fault zones with lab and field data. • UAV imaging used for detailed fracture network analysis in caprocks. • Stress-permeability experiments simulate in-situ conditions for leakage. • Numerical models evaluate permeability across different fault areas. • Framework links fracture analysis with geological leakage models for CCS. [ABSTRACT FROM AUTHOR]

• Low permeability barriers modulate fluid circulation to favour seismicity. • The unrest of 1982–84 decelerated after a seismic swarm on April 1st, 1984. • The 2005–23 uplift is associated with higher (and increasing) b -value than in 1982–84. • The current uplift will likely proceed until fracturing allows fluid depressurization. Changes in seismicity with time and location are diagnostic signals for understanding the dynamics of volcanic unrest. We used these signals at the Campi Flegrei caldera, in southern Italy, to investigate how structural changes have determined three styles of unrest since 1982, distinguished by a ground uplift (measured at Pozzuoli, near the centre of the caldera) of 178 cm in 1982–84; a subsidence of 93 cm in 1985–2005; and an uplift of 118 cm between 2005 and November 2023. Double-difference seismic locations and concentrations of seismic energy release have revealed impermeable horizons that correspond to the cap rock and self-sealed base of the geothermal system at depths of 1.5 and 3 km, respectively. Most earthquakes have been shallower than 3 km, consistent with the brittle upper crust being stretched over a zone of pressurization below the geothermal system. The 1982–84 uplift decayed after a major seismic swarm on April 1st, 1984, breached the lower impermeable horizon, which increased the flux of escaping gas and reduced the source pressure. Continued gas escape promoted subsidence until the lower horizon had resealed itself and initiated a new episode of uplift while gas from depth re-accumulated beneath. Compared with 1982–84, a greater proportion of recent seismicity has occurred at shallower depths below the actively degassing fumaroles of Solfatara-Pisciarelli, north-east of Pozzuoli. The associated high seismic b ‐values, between 1 and 2, are consistent with high fluid pressures and, hence, with locations more favourable to fracturing. Continued uplift may thus persist until fracturing of the shallow crust allows faster rates of gas release and depressurization of the pressure source. [Display omitted] [ABSTRACT FROM AUTHOR]

Geothermal energy offers great advantages in cost, reliability and environmental friendliness compared with conventional fossil fuels; geothermal energy is recommended and has been identified as a renewable and alternative energy source. Two of the pre-requisites for the exploitation of geothermal energy are reservoir and cap rock, and the mechanical properties and permeability behavior of reservoir and cap rock have a great influence on the exploitation of geothermal energy. This study presents a series of experimental results that analyze the effects of temperature (25, 100, 200, 300, 400, 500, 600, 700 and 800 °C) on the physical properties and mechanical and permeability behavior of sandstone. According to the physical test findings, the critical temperature (T c ) that induces changes in the mechanical and permeability behavior of sandstone was identified as 400–500 °C. A more obvious decreasing trend in those physical properties, i.e., weight, density, P-wave velocity, S-wave velocity, dynamic elastic modulus and Poisson’s ratio, can be observed with the increase in temperature after T c compared to that observed before T c . The triaxial compression coupled with the transient pulse permeability test results showed that increasing temperature leads to an increase of cohesion and decrease of internal friction angle before T c , and the opposite trends were observed after T c . A decrease of nearly 20% in elastic modulus was observed after 800 °C compared with room temperature. The initial permeability of sandstone under certain pressure conditions was found to increase nonlinearly with the increase in temperature. Those findings are further discussed in the SEM and XRD analysis, according to which the material composition and state of sandstone as well as the micro-structure changed dramatically with the increase in temperature. Furthermore, a series of empirical relations between the temperatures and physical and mechanical properties of sandstone were derived, and are expected to aid in geothermal energy extraction from super-critical temperature resources. [ABSTRACT FROM AUTHOR]

Cap-rock integrity is of paramount importance during injection and subsequent long-term storage of CO 2 in the subsurface. Pre-existing (natural) and man-induced fractures in the cap rock represent potential flow paths out of the storage formation. In this study, a first-order semi-analytical model of flow through a vertical fracture penetrating cap rock is constructed taking the stress-dependent fracture permeability into account. The model is then applied to study the effects of in-situ stress normal to fracture on the flow rate through the fracture. The flow rate increases nonlinearly with the reservoir pressure, which is due to a combined effect of nonlinear fracture deformation law and the cubic law governing the flow rate. [ABSTRACT FROM AUTHOR]

The permeability of the cap rock is one of the most important properties for determining whether an injected fluid can be sequestered as desired. A literature review on many previously conducted investigations shows that the mechanical properties of a clayey cap rock, such as Young’s moduli and Poisson’s ratios, are relatively constrained to a small range of potential values in comparison to the permeability, which can vary greatly by many orders of magnitude. We found that the shear stress on the interface between the aquifer and cap rock results in very different temporal behaviors in response to different cap rock permeability. The largest shear stress changes concentrate on the near well region and remain stationary over a long period of time if the cap rock has very low permeability. The shear stresses increase greatly in the near well region at early times but the largest increases tend to migrate to the far side for semi-pervious or pervious cap rock conditions. Shear stress near the well may experience a reversion at the interface due to the delayed expansion of the cap rock if the cap rock is semi-pervious and more expansive than the aquifer formation. Because of the difficulty in measuring the stresses at depth, these stress changes may only be inferred from in-direct signals, such as induced seismicity. This poses the possibility that we may be able to inversely evaluate whether a cap rock formation is tight (very impermeable), or semi-pervious or even permeable by detecting the temporal and spatial occurrences of seismic swarms on the rock interface associated with fluid injection. [ABSTRACT FROM AUTHOR]

Permeability of nonsaline cap rock and interlayers is a key parameter for the assessment of the tightness of gas storage caverns in bedded salt formations. X-ray Diffraction, permeability tests, Scanning Electron Microscope studies and theoretical analyses have been performed for the mudstone cap rock and interlayers of a potential cavern in a bedded salt formation. The results show that the permeability of cap rock and interlayers is in the range of 10 − 18 –10 − 20 m 2 , whereas the interface in between salt and interlayer behaves as if impervious. Applied confinement conditions significantly affect the permeability. The higher the applied hydrostatic pressure, the lower the permeability. Permeability decreases more than one order of magnitude with hydrostatic pressure increases, up to a certain “compression threshold pressure”. Permeability remains virtually constant, at an extremely low magnitude, once the hydrostatic pressure exceeds this “compression threshold pressure”. The intrinsic reasons for the low permeability have been revealed by SEM studies, and are as follows: (1) the grains making up the bulk of the mudstone are very small and extremely tightly cemented; secondary minute clay minerals completely fill the pores and fissures between grains of quarts and feldspar, etc., resulting in very little residual void space and reducing connectivity for fluid penetration; and (2) the boundaries between quartz, feldspar and other grains are mainly plate-shape cracks that are poorly interconnected while the finer matrix is very tight and crack-free. The mechanical compaction investigation shows that the plate-shape cracks are much easier to be compacted than sphere-shape pores, which contributes significantly to the decrease in permeability. A capillary tube model suggests that permeability decreases very rapidly in the initial stages of compaction, but decreases extremely slowly in subsequent stages. So the permeability obviously behaves differently before and after the “compression threshold pressure”. By comparison with previous studies, the research we launched demonstrates that the cap rock and interlayers are characterized by extremely low permeability in compression regions. Hence the requirements of tightness (except for the possible presence of Excavation Disturbed Zones) are basically guaranteed. Also, a recommendation is expressed as: to ensure higher tightness and safety, reasonable design and operating programs should be adopted to reduce the EDZs as much as possible. [ABSTRACT FROM AUTHOR]

• CO 2 degassing and faults/fractures in the Monterotondo-Sasso Pisano transfer fault. • CO 2 flux, temperature, volumetric fracture intensity and permeability survey. • Discrete Fracture Network (DFN) modeling to reconstruct the fault architecture. • CO 2 flux and steam change in relation to the architecture of the fault damage zone. • Increased degassing rates evidence enhanced structural permeability. Carbon dioxide is one of the most important gasses naturally released from geothermal systems. Establishing the processes and pathways that regulate the CO 2 diffuse degassing can provide valuable information for exploration and exploitation purposes of geothermal reservoirs. In this work, a high-resolution CO 2 flux (with records up to 2927 g m–2 d–1) and soil temperature (with records up to 98.8 °C) survey was carried out along with detailed fracture parameters measurements in a selected area of the Monterotondo Marittimo-Sasso Pisano transfer fault (Larderello geothermal system, Tuscany, Italy). The main aim was to define the behavior of diffuse CO 2 through the fault system and investigate how the soil CO 2 flux and steam change with respect to the architecture of the fault damage zone (i.e., volumetric fracture intensity, permeability, and persistence of the fractures). The presence of multiple populations of CO 2 flux suggested that three different transport mechanisms control soil degassing: i) purely diffusive, ii) mixed diffusive-advective, and iii) purely advective, characterized by efflux values of <20, between 20 and 300 and >300 g m–2 d–1, respectively. The spatial distribution of these fluxes well agrees with the fracture distribution and features of the Jurassic radiolarite (Diaspri Fm) dissected by NNE-striking faults. Areas with high CO 2 emissions are indeed able to reveal major upflow areas from deep reservoirs through deep-reaching permeable fault zones. The interaction between pre-existing fractures and fracture-related fault-zone locally enhances the secondary rock permeability as highlighted by the correlation between Discrete Fracture Network (DFN) modeling and advective flux. Eventually, by normalizing the CO 2 output to the fault strip (1350 m2), a release of CO 2 equal to ∼155 t d–1 km–2 was estimated. [ABSTRACT FROM AUTHOR]

• CO 2 storage efficiency factors were reassessed for saline formations by modeling. • New experimental relative permeability data were applied for various environments. • Tighter reservoirs resulted higher volumetric and microscopic efficiency factors. • Dolomite and limestone had higher ranges of storage efficiencies than clastics. Saline formations are attractive geologic reservoirs for permanent carbon dioxide (CO 2) storage. The U.S. Department of Energy's National Energy Technology Laboratory (DOE-NETL) has worked to develop and refine methods and tools for the calculation of CO 2 storage potential in subsurface reservoirs. DOE-NETL's CO 2 -SCREEN provides an online tool for executing these storage methods. CO 2 storage efficiency terms are input parameters in DOE-NETL's methods and equations embedded in the CO 2 -SCREEN, which assesses pore space available for CO 2 storage. In this work, a modeling workflow was initiated to refine two CO 2 storage efficiency terms - volumetric displacement (E V) and microscopic displacement (E d). The models are based on new experimental relative permeability data that are specific to homogenous lithology and depositional environments of key subsurface saline formations targeted for CO 2 storage. In future work, heterogenous features will be added to this initial modeling effort to update efficiency factors as described in DOE-NETL's methods and CO 2 -SCREEN tool. E V accounts for the volume utilized in the reservoir under the areal plume, while E d accounts for saturation values in the plume to assess efficiency of CO 2 storage at the pore scale. The results of this work are significant in that prior values were based on a limited geologically non-specific relative permeability data set that were collected prior to 2009. Specifically, we applied numerical simulations using TOUGH3 models to update CO 2 storage efficiency values for supercritical CO 2 injection into brine-saturated reservoirs for three lithologies (clastics, limestone, dolomite) and six depositional environments (Marginal Marine, Strand Plain, Deltaic Complex Fluvial, Aeolian, Shallow Marine, and Reef) that have a high potential for geologic CO 2 storage. Experimental relative permeability data in cores from these environments were utilized in the models with corresponding rock type/sedimentary environment. Results of this study showed that dolomite followed by limestone generated higher ranges of storage efficiency compared to clastics. The updated values provided a tighter efficiency range for clastics, lower P 10 but higher P 90 range for limestone, and higher P 10 and P 90 for dolomite. In general, tighter reservoirs with relatively low permeability and porosity were associated with higher E V and E d , showing efficient reservoir and pore utilization in these scenarios. High reservoir pressure and temperature associated with increasing depth increased the E V , and high CO 2 injection rates resulted in increases in E V and E d , while the impact of permeability anisotropy was minimal after the 30-year injection period. [Display omitted] [ABSTRACT FROM AUTHOR]

The self-sealing of caprocks plays a vital role in CO 2 geological sequestration. However, the mechanisms by which distinctive mineral combinations and types of caprock bring about self-sealing are unclear. Studies of the self-sealing of caprocks with different mineral combinations and rock types promise to effectively identify the self-sealing capabilities of cap rocks and evaluate the long-term safety of CO 2 geological sequestration. This study focuses mainly on the mechanisms of self-sealing in three caprocks, specifically the shale of the Qingshankou Formation in the Songliao Basin, the calcareous mudstone of the Da'anzhai Formation in the Sichuan Basin, and the shale of the Yanchang Formation in the Ordos Basin. This study applies the key technology of CO 2 –fluid–rock numerical simulation and petrological and analytical methods to systematically investigate the self-sealing capability of these caprocks, which have different mineral compositions, and identify the key minerals that trigger self-sealing. The results show that the key minerals that can trigger self-sealing after CO 2 injection are carbonates such as calcite, siderite, and dolomite and clays such as kaolinite. The CO 2 –fluid–rock interactions in feldspar- and illite-rich shale are relatively mild, which is conducive to the safe geological sequestration of CO 2. In contrast, the CO 2 –fluid–rock interactions in carbonate-rich shale are violent and fluctuate greatly, which is not conducive to the short-term safe sequestration of CO 2 , but they are favorable for the safe sequestration of CO 2 in the medium to long term. After CO 2 injection, the main minerals precipitated in a carbonate-rich shale are K-feldspar and small amounts of ankerite and dawsonite. The main minerals precipitated in illite-rich shale are quartz and small amounts of ankerite and dawsonite. The results of this study show that it is possible to effectively evaluate the sealing capability of caprocks, thus providing a basis for the safe sequestration of CO 2. • Key precipitated minerals that trigger self-sealing are k-feldspar, dawsonite and ankerite. • Key dissolution minerals that affect self-sealing are albite, calcite, dolomite and siderite. • Feldspar- and illite-rich shales react mildly with injected CO 2 , enabling the safe geological sequestration of CO 2. [ABSTRACT FROM AUTHOR]

We present characterization and geochemical data from a core-flooding experiment on a sample from the Three Fingers evaporite unit forming the lower extent of caprock at the Weyburn-Midale reservoir, Canada. This low- permeability sample was characterized in detail using X-ray computed microtomography before and after exposure to CO2-acidified brine, allowing mineral phase and voidspace distributions to be quantified in three dimensions. Solution chemistry indicated that CO2-acidified brine preferentially dissolved dolomite until saturation was attained, while anhydrite remained unreactive. Dolomite dissolution contributed to increases in bulk permeability through the formation of a localized channel, guided by microfractures as well as porosity and reactive phase distributions aligned with depositional bedding. An indirect effect of carbonate mineral reactivity with CO2-acidified solution is voidspace generation through physical transport of anhydrite freed from the rock matrix following dissolution of dolomite. The development of high permeability fast pathways in this experiment highlights the role of carbonate content and potential fracture orientations in evaporite caprock formations considered for both geologic carbon sequestration and CO2- enhanced oil recovery operations. [ABSTRACT FROM AUTHOR]

Capillary trapping of a nonwetting fluid phase in the subsurface has been considered as an important mechanism for geologic storage of carbon dioxide (CO2). This mechanism can potentially relax stringent requirements for the integrity of cap rocks for CO2 storage and therefore can significantly enhance storage capacity and security. We here apply ganglion dynamics to understand the capillary trapping of supercritical CO2 (scCO2) under relevant reservoir conditions. We show that, by breaking the injected scCO2 into small disconnected ganglia, the efficiency of capillary trapping can be greatly enhanced, because the mobility of a ganglion is inversely dependent on its size. Supercritical CO2 ganglia can be engineered by promoting CO2 -water interface instability during immiscible displacement, and their size distribution can be controlled by injection mode (e.g., water-alternating-gas) and rate. We also show that a large mobile ganglion can potentially break into smaller ganglia due to CO2-brine interface instability during buoyant rise, thus becoming less mobile. The mobility of scCO2 in the subsurface is therefore self-limited. Vertical structural heterogeneity within a reservoir can inhibit the buoyant rise of scCO2 ganglia. The dynamics of scCO2 ganglia described here provides a new perspective for the security and monitoring of subsurface CO2 storage. [ABSTRACT FROM AUTHOR]

Geologic storage of CO2 requires that the caprock sealing the storage rock is highly impermeable to CO2. Swelling clays, which are important components of caprocks, may interact with CO2 leading to volume change and potentially impacting the seal quality. The interactions of supercritical (sc) CO2 with Na saturated montmorillonite clay containing a subsingle layer of water in the interlayer region have been studied by sorption and neutron diffraction techniques. The excess sorption isotherms show maxima at bulk CO2 densities of ≈0.15 g/cm3, followed by an approximately linear decrease of excess sorption to zero and negative values with increasing CO2 bulk density. Neutron diffraction experiments on the same clay sample measured interlayer spacing and composition. The results show that limited amounts of CO2 are sorbed into the interlayer region, leading to depression of the interlayer peak intensity and an increase of the d(001) spacing by ca. 0.5 Å. The density of CO2 in the clay pores is relatively stable over a wide range of CO2 pressures at a given temperature, indicating the formation of a clay-CO2 phase. At the excess sorption maximum, increasing CO2 sorption with decreasing temperature is observed while the high-pressure sorption properties exhibit weak temperature dependence. [ABSTRACT FROM AUTHOR]

Mitigation strategies for sealing high permeability regions in cap rocks, such as fractures or improperly abandoned wells, are important considerations in the long term security of geologically stored carbon dioxide (CO2). Sealing technologies using low-viscosity fluids are advantageous in this context since they potentially reduce the necessary injection pressures and increase the radius of influence around injection wells. Using aqueous solutions and suspensions that can effectively promote microbially induced mineral precipitation is one such technology. Here we describe a strategy to homogenously distribute biofilm-induced calcium carbonate (CaCO3) precipitates in a 61 cm long sand-filled column and to seal a hydraulically fractured, 74 cm diameter Boyles Sandstone core. Sporosarcina pasteurii biofilms were established and an injection strategy developed to optimize CaCO3 precipitation induced via microbial urea hydrolysis. Over the duration of the experiments, permeability decreased between 2 and 4 orders of magnitude in sand column and fractured core experiments, respectively. Additionally, after fracture sealing, the sandstone core withstood three times higher well bore pressure than during the initial fracturing event, which occurred prior to biofilm-induced CaCO3 mineralization. These studies suggest biofilm-induced CaCO3 precipitation technologies may potentially seal and strengthen fractures to mitigate CO2 leakage potential. [ABSTRACT FROM AUTHOR]

CO2 capture and geologic sequestration is one of the most promising options for reducing atmospheric emissions of CO2. Its viability and long- term safety, which depends on the caprock's sealing capacity and integrity, is crucial for implementing CO2 geologic storage on a commercial scale. In terms of risk, CO2 leakage mechanisms are classified as follows: diffusive loss of dissolved gas through the caprock, leakage through the pore spaces after breakthrough pressure has been exceeded, leakage through faults or fractures, and well leakage. An overview is presented in which the problems relating to CO2 leakage are defined, dominant factors are considered, and the main results are given for these mechanisms, with the exception of well leakage. The overview includes the properties of the CO2-water/brine system, and the hydromechanics, geophysics, and geochemistry of the caprock-fluid system. In regard to leakage processes, leakage through faults or fracture networks can be rapid and catastrophic, whereas diffusive loss is usually low. The review identifies major research gaps and areas in need of additional study in regard to the mechanisms for geologic carbon sequestration and the effects of complicated processes on sealing capacity of caprock under reservoir conditions. [ABSTRACT FROM AUTHOR]

Layered low permeability rock units, like shales, represent seals or 'cap-rocks' in a variety of geological settings. A continuous increase in the fluid pressure gradients across a virtually impermeable rock layer will ultimately lead to hydro-fracturing. Depending on the boundary conditions, such fracturing may lead to the formation of a set of sub-parallel cracks oriented more or less perpendicular to the cap-rock layer. In this article, we propose a new numerical model that describes interactions between multiple cross-cutting fractures in an elastic low permeability rock layer. The width of each fracture and the spacing between them are modeled as a force balance between the fluid pressure and the elastic forces in the cap-rock and between each fracture. The model indicates that the system of fractures evolves toward a spatially periodic steady-state distribution with a fixed fracture spacing and aperture. The results are similar for incompressible and compressible fluids. The steady-state conditions depend on only two dimensionless parameters, and the fracture spacing is only weakly dependent on the cap-rock thickness. This is in contrast to fracturing produced by simple extension of an elastic rock layer beyond the fracture strength, in which case fracture spacing is proportional to layer thickness. [ABSTRACT FROM AUTHOR]

Abstract: Eruptions of intermediate magma may be explosive or effusive. The development of open system degassing has been proposed as a pre-requisite for effusion of intermediate magma, however processes leading to open system degassing are poorly understood. To better understand degassing processes during lava dome extrusion we report high temporal-resolution SO2 emission rate measurements collected with an ultra violet imaging camera at Santiaguito, Guatemala. Santiaguito is an ideal case study as the dome lava is compositionally very similar to products of the 1902 Plinian eruption of the parental Santa María volcano. We find that degassing is weak (0.4–1kgs−1) but continuous, and explosions are associated with small increases in emission rates (up to 2–3kgs−1). Continuous repose degassing occurs through a shallow cap rock which likely represents a proto-crust on the block lava flow which is extruded from the same vent. The continual permeability of the upper conduit argues against a mechanism of explosion triggering in which gas pressure builds beneath a viscous cap rock or plug. Rather, we consider degassing data better consistent with a model of shear-fracturing at the conduit margins. Using field constraints, we model the viscosity of Santiaguito magma as a function of depth and show that conditions for shear-fracturing are met from 150–600m to the surface. This is in line with independent estimates of explosion initiation depth. We show that repose timescales are orders of magnitude longer than the timescale for shear fracture, and suggest that explosions are triggered when a continuous network of smaller-scale fractures develops, at which point decompression occurs and an explosion is triggered. Fracture healing occurs by viscous relaxation however near to the surface where viscosity is highest, an unconsolidated gouge layer may develop. Our model implies that the observed explosions are a by-product of extrusion. Shear-fracturing can drive open system degassing of crystal rich intermediate magma at shallow levels in the conduit, as high magma viscosity is able to overcome the low strain rates associated with slow ascent of magma. [Copyright &y& Elsevier]

Abstract: We present an experimental study of the retention/flow properties of the caprock of the Rousse depleted gas field, where up to 120000 tons of CO2 are to be injected over a 2-year period. One of the caprock samples examined comes from the carbonated breccias overlying the reservoir, a deep Jurassic horst, whereas the other samples come from the 2000 m-thick Upper Cretaceous marl (carbonated turbidites) located above these breccias and the reservoir. The single-phase (brine) intrinsic permeabilities of the marly samples turn out to be extremely low and stress-sensitive. They vary from 20-25 nanoDarcy for the most permeable sample at low stress, to below 1 nanoDarcy at effective stresses in the range of 10 MPa and above. These latter values are lower by at least one order of magnitude than the published values for the caprocks of the Weyburn field and Utsira aquifer. However, the permeability of the brecciated sample is considerably higher, and decreases from ca. 0.1 to 0.003 milliDarcy when the effective stress increases to 20 MPa, which possibly reflects some of the reservoir petrophysical behavior. Gas breakthrough (BT) experiments are undertaken on two of the marly samples fully saturated with brine, using either CO2 or nitrogen as the gas phase. One sample is able to resist CO2 excess pressures as large as 7.6 MPa, whereas in the other more permeable sample a relative pressure of 4.5-6 MPa is enough to induce the BT of nitrogen, a gas with interfacial properties more favourable than CO2 to capillary sealing. Nitrogen flow following BT is extremely limited, with an effective permeability below 1 nanoDarcy. Upon subsequent sample resaturation with brine and then BT with CO2, some alteration of the sealing behaviour is observed, manifested by a decreased BT pressure and an increased gas effective permeability. [Copyright &y& Elsevier]

Abstract: In geologic carbon sequestration, caprock fractures may act as leakage pathways, threatening the long term sealing ability of the formation. A flow-through experiment was performed to investigate fracture evolution of a fractured carbonate caprock during simulated leakage of CO2-acidified brine. The initial brine composition represented that of a CO2-saturated brine having previously reacted with the injection formation minerals resulting in a starting pH of 4.9. Experimental temperature and pressure conditions were 40 °C and 10 MPa, corresponding to injection at a depth of 1 km. A combination of X-ray computed tomography and scanning electron microscopy was used to observe fracture evolution and investigate the mineralogical changes that occurred along the fracture wall. After one week of brine flow, the cross-sectional fracture area increased by an average of 2.7 times that of the initial fracture. The fracture surface was not eroded uniformly, with the largest areas of aperture growth corresponding to direct contact between the acidified brine and calcite. This preferential dissolution of calcite led to a large increase in fracture surface roughness and in some instances, created a silicate mineral-rich microporous coating along the fracture wall. Results from this study suggest that the clay content of low permeability carbonate formations may be an important factor in controlling their long term integrity while in contact with acidified brine and should be considered when selecting appropriate injection sites for geologic CO2 sequestration. [Copyright &y& Elsevier]

Abstract: Relating to the assessment of the cap rock integrity on CO2 geological sequestration, we measured threshold pressure for supercritical CO2 under pressure and temperature conditions of 1,000 m depth (i.e., 10 MPa and 40 °C). The present study aims to quantify various factors which affect the variability of rock’s threshold pressure and to model the threshold pressure range of a cap rock. We prepared sintered compacts composed of uniformly-sized silica glass beads (0.2–10 μm), and examined a correlation between threshold pressure and permeability for each diameter. The result revealed that threshold pressure of sintered compacts increased drastically with a decrease of component particle size. Moreover, there existed a good linearity between the logarithm of threshold pressure and the logarithm of permeability. The fitted line is an important basis specifically from a viewpoint of safety assessment because it corresponds to the lower limit of threshold pressure of homogeneous rocks. [Copyright &y& Elsevier]

Abstract: Important parameters for the determination of fluid transport in reservoir rocks are capillary pressures and relative permeabilities for the CO2/brine system. These factors influence the plume migration, residual CO2 trapping and CO2 dissolution in the reservoir brines. CO2-brine relative permeabilities for different rock types are rare in public literature and usually adapted from mathematical relations or from more recent experimental data. The experimental data vary greatly in saturation and relative permeability endpoints, between 10 and 100%. It is necessary to reduce the uncertainty in the data range, since these parameters are sensitive and indispensable for the numerical simulation of the evolution of a CO2 plume in the subsurface. The petrophysical properties of caprocks are the limiting factor to the amount of CO2 stored in potential storage sites. The caprock sealing capacity is determined by the capillary pressure (or column height) at which the trapped fluid starts leaking through a caprock. These rocks have high capillary threshold pressures, which, combined with wettability and interfacial tension (IFT), determine the final column height that a seal can hold. Those three factors - capillary pressure, wettability and IFT - play an important role in the geological storage of CO2 in controlling the potential of CO2 moving through the seal. The capillary threshold pressures need to be determined accurately toestimate brine displacement in caprocks and hence the onset of viscous flow or leakage to the surface. Within the framework of the Carbon Capture Project (CCP3), we plan to establish standard experimental protocols with academic and/or commercial laboratories. [Copyright &y& Elsevier]

Abstract: Maintaining caprock integrity is key to long-term geological storage of CO2, as large-scale structural trapping below a top seal is one of the most important storage mechanisms. Evaporite sequences, such as anhydrite, form the caprock of many depleted oil and gas reservoirs, as well as several current CCS sites and natural CO2 analogues. This paper is based on two studies by Hangx et al. on the mechanical and volumetric (permeability) behavior of Zechstein anhydrite. [Copyright &y& Elsevier]

Abstract: Using a combination of experimental (petrophysical and mineralogical) methods, the effects of high-pressure CO2 exposure on fluid transport properties and mineralogical composition of two pelitic caprocks, a limestone and a clay-rich marl lithotype have been studied. Single and multiphase permeability tests, gas breakthrough and diffusion experiments were conducted under in situ p/T conditions on cylindrical plugs (28.5mm diameter, 10–20mm thickness). The capillary CO2 sealing efficiency of the initially water-saturated sample plugs was found to decrease in repetitive gas breakthrough experiments on the same sample from 0.74 to 0.41MPa for the limestone and from 0.64 to 0.43MPa for the marl. Helium breakthrough experiments before and after the CO2 tests showed a decrease in capillary threshold (snap-off) pressure from 1.81 to 0.62MPa for the limestone. Repetitive CO2 diffusion experiments on the marlstone revealed an increase in the effective diffusion coefficient from 7.8×10−11 to 1.2×10−10 m2. Single-phase (water) permeability coefficients derived from steady-state permeability tests ranged between 7 and 56nano-Darcy and showed a consistent increase after each CO2 test cycle. Effective gas permeabilities were generally one order of magnitude lower than water permeabilities and exhibit the same trend. XRD measurements performed before and after exposure to CO2 did not reveal any distinct change in the mineral composition for both samples. Similarly, no significant changes were observed in specific surface areas (determined by BET) and pore-size distributions (determined by mercury injection porosimetry). High-pressure CO2 sorption experiments on powdered samples revealed significant CO2 sorption capacities of 0.27 and 0.14mmol/g for the marlstone and the limestone, respectively. The changes in transport parameters in the absence of detectable mineral alterations may be explained by carbonate dissolution and further precipitation along a pH profile across the sample plug which would not be subject to quantitative mineral alteration. [Copyright &y& Elsevier]

Limestone caprock permeability and damage characteristics have a significant impact on the tightness and stability of salt cavern gas storage. To investigate the gas sealing capacity of limestone as caprock for a gas reservoir at different burial depths, triaxial compression coupled with permeability tests of limestone subjected to different confining pressures and temperatures were carried out using the improved MTS 815 test machine. After the tests, X-ray micro-computed tomography (μCT) is used to perform CT scanning of the limestone sample after seepage failure to estimate the rock meso-damage. The experimental results depicted that: (1) At the confining pressures of 10 MPa, 20 MPa and 30 MPa, the final permeability increases with the increase of temperature, while at the confining pressures of 40 MPa, the evolution of the final permeability is opposite. (2) The pore radius of limestone is concentrated in the range of 0–200 μm, and the pore with a radius greater than 1200 μm is the main permeability channel with the greatest contribution. The final permeability is positively correlated with porosity. (3) The fractal dimension decreases with the increase of confining pressure, and some areas of rock do not have fractal characteristics when the confining pressure reaches 40 MPa. Permeability after rock damage is positively correlated with the fractal dimension and the maximum pore diameter and negatively correlated with the tortuous fractal dimension, according to the fractal permeability model. These experimental results and analyses provide scholars and engineers with a thorough understanding of cap rock tightness in the construction of deep-earth gas storage reservoirs. • The permeability evolution of limestone rock under THM coupling was investigated. • The meso-damagee characteristics base on CT was obtained. • The effectiveness of the fractal permeability model is verified. [ABSTRACT FROM AUTHOR]

Abstract: The capture and geological CO2 storage (CCGS) in deep aqui fers, depleted oil and gas fields and coal seams appears to be one of the main solutions to reduce greenhouse gases release to the atmosphere (IPCC, 2005). The geochemical reactivity between the mixed fluids (supercritical CO2 and brine) and the clayey caprock formations under physicochemical conditions of geological storage remain largely under-investigated. The caprock is characterized by inherent properties notably supported by a high clayey content such as low reactivity, low permeability and high elasticity/plasticity. This study presents experimental and modeling results regarding the geochemical reactivity of two caprock samples under CO2 storage conditions: a rock sample from the Chinle formation in Moab (Utah–USA) and a sample from the Comblanchie n formation in Charmotte (Paris Basin–France). Experiments were conducted in pressurized cells where fluids (CO2 and brine) are maintained at constant temperature (80 to 150 ∘C) and pressure (1 to 150 bar). The duration of the experiments ranged from 30 to 360 days. The brine was synthesized as a representative solution of a saline aquifer. In the experiments, carbonate minerals (dolomite, calcite) dissolve partially or totally in the short term. In the long -term experiments, a new form of complex carbonate precipitates. To evaluate clay minerals reactivity, the same series of experiments were performed with a purified mixed -layer illite/smectite mineral (I/S), illite and smectite. The I/S reveals a clear stability towards CO2 whereas illite and smectite tend to be destabilized in the long -term. Kaolinite is the most reactive clay mineral as it dissolves totally in the long -term experiments. To predict and compare the geochemical reaction pathways, reactive transport modeling was performed focusing on the be havior of the cap -rock at the timescale of the experiments (30 to 365 days). Calculations were also extended to duration up to 10,000 years which is the relevant timescale for the long term safety assessment of CO2 storage. [Copyright &y& Elsevier]

• The reference point for convective instability is the concentration perturbation peak. • The perturbation peak relative to the low-permeability region controls the onset time. • The onset time due to the layered permeability is sensitive to the Rayleigh number. • The effect of permeability on onset depends on the variation whether smooth or sharp. Deep saline aquifers used for CO 2 sequestration are commonly made of sedimentary formations consisting of several layers of distinguishable permeability. In this work, the effect of a non-monotonic, vertically varying permeability profile on the onset of convective instability is studied theoretically using linear stability analyses. The onset time depends on the interaction between the permeability profile and the location of the concentration perturbation peak beyond which the concentration of CO 2 decays. A thin low-permeability layer can either accelerate or delay the onset time of the convective instability depending on the nature of the permeability variation – whether the permeability transition is smooth or layered, the Rayleigh number (Ra), and the location of the permeability change (a ^) relative to the perturbation peak (a ^ c *), which scales as a ^ c * ≈ 14 R a − 1 for homogeneous systems. However, the low permeable layer has no effect on the onset time when it is near the lower boundary of a medium with sufficiently large Ra ( a ^ c * ≪ a ^). This nontrivial dependence highlights the implication of ignoring geological features of a small spatial extent, indicating the importance of a detailed characterization of CO 2 storage sites. [ABSTRACT FROM AUTHOR]