Natural CO2 Reservoir Research Articles

Effects of inorganic CO2 intrusion on diagenesis and reservoir quality of lacustrine conglomerate sandstones: Implications for geological carbon sequestration

Mantle-sourced fluids are common in rift basins and often migrate into the reservoir along deep faults. They have a significant role in hydrocarbon evolution and reservoir quality modifications. In this study, we selected Chagan Sag in China as an example and applied reactive transport modeling to explore the influence of mantle-derived CO2 on diagenesis and reservoir quality evolution in the Lower Cretaceous Bayingebi conglomerate reservoirs. The geochemical modeling constrained by natural CO2 reservoirs provides beneficial information on the underground physical processes and chemical reactions during CO2 injection. This is also an efficient means of validating geological carbon sequestration models. Petrographic, geochemical, and modeling data reveal that CO2 intrusion could reduce the reservoir porosity and permeability via significant CO2-water-mineral interactions. Ankerite and illite are the dominant diagenetic minerals responsible for reservoir quality reduction. Among the different lithologies, the higher reservoir quality conglomerate is mainly caused by its high initial porosity and small quantities of clay minerals, with relatively weak carbonate cementation. The lower reservoir quality finer-grained conglomeratic siltstone is caused by intensive albitization, carbonation, and illitization. In the long-term CO2-water-rock interaction process, CO2 can be sequestered through the precipitation of secondary carbonate minerals such as ankerite and dolomite.

Evolution of structural and mechanical properties of concrete exposed to high concentration CO2

There are many natural high concentration CO2 reservoirs in the deep subsurface worldwide, and there is a potential for CO2 leakage from deep CO2 reservoirs to shallower underground spaces. As a result, underground mining and tunnel construction may encounter zones with high concentration CO2, which raises concern of concrete carbonation. Concrete carbonation under low CO2 concentration may increase the strength of concrete, but concrete carbonation under high concentration CO2 may cause concrete damage. High concentration CO2 may significantly increase the carbonation rate of concrete, which causes the strength and service life of concrete to decrease. In order to investigate the effect of CO2 concentration on concrete carbonation, this paper studied the carbonation process of concrete samples in dry gas, pure water and 70% relative humidity (RH) environments with 100 kPa, 500 kPa and 1000 kPa CO2 partial pressures. The chemical compositions, pore structure and mechanical properties of the concrete samples were also studied. The results showed that the carbonation environment affected the crystallization process of carbonation products. The existence of water increased the level of concrete carbonation in pure water environment, and some C-S-H also reacted with CO2 to produce aragonite. Therefore, after 28 d carbonation of concrete in 100 kPa CO2, aragonite existed in pure water environment but did not exist in dry gas environment. For all carbonation environments, the compressive strength of concrete increased after carbonation in 100 kPa and 500 kPa CO2, but the compressive strength of concrete first increased and then decreased in pure water and 70% RH environment with 1000 kPa CO2. In summary, if the concentration of CO2 reaches a certain level (i.e., 1000 kPa partial pressure), the CO2-induced carbonation can eventually lead to concrete damage.

Modelling of long-term along-fault flow of CO2 from a natural reservoir

As part of the European ACT-sponsored research consortium, DETECT, we developed an integrated characterisation and risk assessment toolkit for natural fault/fracture pathways. In this paper, we describe the DETECT experimental-modelling workflow, which aims to be predictive for fault-related leakage quantification, and its application to a field case example for validation. The workflow combines laboratory experiments to obtain single-fracture stress-dependent permeabilities; single-fracture modelling for stress-dependent relative permeabilities and capillary pressures; fracture network characterisation and modelling for the caprock(s); upscaling of properties and constitutive functions in fracture networks; and full compositional flow modelling at field scale.Here we focus on the application of the workflow to the Green River site in Utah. This is a rare case of leakage from a shallow natural CO2 reservoir, where CO2 (dissolved or gaseous) migrates along two fault zones to the surface. This site provides a unique opportunity to understand CO2 leakage mechanisms and volumes along faults, because of its extensive characterisation including a large dataset of present-day CO2 surface flux measurements as well as historical records of CO2 leakage in the form of travertine mounds. When applied to this site, our methodology predicts leakage locations accurately and, within an order of magnitude, leakage rates correctly without extensive history matching. Subsequent history matching achieves accurate leak rate matches within a-priori uncertainty ranges for model input parameters.

Mineralogical and geochemical changes in conglomerate reservoir rocks induced by CO2 influx at Mih\xe1lyi-R\xe9pcelak natural analogue, NW-Hungary

A temporary solution to massive anthropogenic CO2 emissions can be the capture of industrial CO2 from flue gas and sequestering it in geological formations. For safe and effective storage of CO2, interaction processes in the rock-pore fluid–CO2 system should be known. Investigation of natural CO2 accumulations provides valuable examples to what physical and chemical effects could be expected during CO2 influx at future CO2 storage sites. One of the key controlling factors of the processes occurring in natural CO2 reservoirs is the lithology of the storage rocks, which is primarily determined by the formation conditions of these rocks. In this respect, the lithologies of individual CO2 accumulation areas influence the processes between the host rock, the pore fluid, and the CO2 in different ways. In the current study, we focus on a well-studied natural CO2 storage reservoir, namely the Mihályi-Répcelak area, NW Hungary. We provide insight into the so far unstudied conglomerate reservoirs that represent a stratigraphically deeper reservoir unit with significantly different lithology and pore water compositions compared to the sandstone reservoirs. Our results indicate that dawsonite /NaAlCO3(OH)2/ formation also affected the conglomerate reservoirs, which indicates that at least part of the CO2 could be trapped in mineral form. An important role of salinity in reducing the CO2 mineral trapping capacity of the storage system is also demonstrated. Furthermore, H isotope analysis of diagenetic kaolinite was applied to trace the origin of the pore water that was present during the rock formation. Based on the data, dawsonite formation was induced by the flux of meteoric water that infiltrated during a warm and humid period and mixed with ascending CO2.

Origin of dawsonite-forming fluids in the Mihályi-Répcelak field (Pannonian Basin) using stable H, C and O isotope compositions: Implication for mineral storage of carbon-dioxide

Natural CO2 reservoirs provide an opportunity to study long-term fluid-rock interactions, which are essential to reassure the safety of mineral storage of carbon-dioxide. The Mihályi-Répcelak field (Pannonian Basin, Central Europe) is one of the largest natural CO2-bearing reservoirs in Europe (25 Mt). The CO2 was trapped in Neogene sandstones, which contain various carbonate minerals (dolomite, ankerite, siderite, dawsonite). To reveal the origin of the parent fluid, from which these minerals precipitated, dawsonite and siderite were separated by a new physical method to minimise the uncertainties in the analysis of their stable isotope composition. The δ13CDaw values range from +1.3‰ to +1.6‰ and the calculated δ13CCO2 values in equilibrium with dawsonite (−4.8‰ - –2.0‰) overlap with the carbon isotope compositions of the local CO2 and the European Subcontinental Lithospheric Mantle (−3.9‰ - –2.1‰). This indicates that the dawsonite-forming CO2 had a magmatic origin. The siderite data indicates that some formed from the magmatic CO2, possibly simultaneously with dawsonite (−6.0‰ - –3.9‰), whereas the rest (−8.4‰ - –6.1‰) formed either from a fractionated CO2 with magmatic origin or before the CO2 invasion. The hydrogen isotope composition of structural OH− of dawsonite (−57‰ to −74‰) was determined and was used to estimate the origin of the interacting porewater. The calculated porewater data (δD: −69‰ - –103‰ and δ18O: −1.4‰ - +4.7‰) indicate that the parent fluid was meteoric water modified by water-rock interaction. Our data allows estimation of the total amount of CO2 stored in the dawsonite-bearing sandstone reservoir to be 25 kg/m3, well in line with previous modelling works, which gives a total of 2.01 × 106 t of CO2, higher than previous estimates.We suggest that individual mineral analysis complemented by hydrogen isotope analysis is to be employed to effectively trace in-reservoir fluid-rock interactions in CO2 reservoirs and provide valuable input data for geochemical modelling for better predicting conditions for mineral storage of CO2.

Quantification of solubility trapping in natural and engineered CO 2 reservoirs

Secure retention of CO 2 in geological reservoirs is essential for effective storage. Solubility trapping, the dissolution of CO 2 into formation water, is a major sink on geological timescales in natural CO 2 reservoirs. Observations during CO 2 injection, combined with models of CO 2 reservoirs, indicate the immediate onset of solubility trapping. There is uncertainty regarding the evolution of dissolution rates between the observable engineered timescale of years and decades, and the >10 kyr state represented by natural CO 2 reservoirs. A small number of studies have constrained dissolution rates within natural analogues. The studies show that solubility trapping is the principal storage mechanism after structural trapping, removing 10–50% of CO 2 across whole reservoirs. Natural analogues, engineered reservoirs and model studies produce a wide range of estimates on the fraction of CO 2 dissolved and the dissolution rate. Analogue and engineered reservoirs do not show the high fractions of dissolved CO 2 seen in several models. Evidence from natural analogues supports a model of most dissolution occurring during emplacement and migration, before the establishment of a stable gas–water contact. A rapid decline in CO 2 dissolution rate over time suggests that analogue reservoirs are in dissolution equilibrium for most of the CO 2 residence time. Supplementary material: Dissolution rate for all plots and exponential function curves for scenarios A and B are available at https://doi.org/10.6084/m9.figshare.c.5476199 Thematic collection: This article is part of the Geoscience for CO 2 storage collection available at: https://www.lyellcollection.org/cc/geoscience-for-co2-storage

Investigation of mineral trapping processes based on coherent front propagation theory: A dawsonite-rich natural CO2 reservoir as an example

After nearly 30 years of research on geological carbon storage, studies providing an in-depth conceptual understanding of mineral trapping processes are still scarce. Based on the reaction front propagation theory, this paper developed a set of concise mathematical models for front propagation and mineral trapping in quasi-2D-advection-diffusion-dispersion-reaction-kinetics systems in the coherent state and explored the nature of long-term mineral trapping processes and the effects of hydrodynamic dispersion on the front propagation. A criterion based on dawsonite volume fraction and front propagation distance was established to determine whether the mineral trapping rate is reaction- or transport-controlled for the coherent reaction fronts. Combined with the numerical simulation, the mantle-magmatic-sourced CO2 invasion, and long-term CO2 storage was investigated for the Hailar natural CO2 reservoir. The conclusions include: (1) The relative errors of the concise models for coherent front propagation speed and mineral trapping rate are 3-10% and 0.5-10%, respectively. (2) For the complete reaction stage, mineral trapping rates are always transport-controlled and are proportional to Darcy velocity, the difference of total dissolved carbon concentrations, and the correction coefficient for the hydrodynamic dispersion; when reaction controlling, the mineral trapping rate is proportional to front propagation distance and upstream dawsonite precipitation rate. (3) Specific results related to propagation speed, front width, hydrodynamic dispersion and mineral trapping rate caused by changing the rate constants of minerals and albite volume fraction were also obtained.

Modelling of Long-term Along-fault Flow of CO2 From a Natural Reservoir

Geological sequestration of CO2 requires the presence of at least one competent seal above the storage reservoir to ensure containment of the stored CO2. Most of the considered storage sites are overlain by low-permeability evaporites or mudrocks that form competent seals in the absence of defects. Potential defects are formed by man-made well penetrations (necessary for exploration and appraisal, and injection) as well as (for mudrocks) natural or injection-induced fracture systems through the caprock. These defects need to be de-risked during site selection and characterisation. A European ACT-sponsored research consortium, DETECT, developed an integrated characterisation and risk assessment toolkit for natural fault/fracture pathways. In this paper we describe the DETECT experimental-modelling workflow, which aims to be predictive for fault-related leakage quantification, and its application to a field case example for validation. The workflow combines laboratory experiments to obtain single-fracture stress-sensitive permeabilities; single-fracture modelling for stress-sensitive relative permeabilities and capillary pressures; fracture network characterisation and modelling for the caprock(s); upscaling of properties and constitutive functions in fracture networks; and full compositional flow modelling at field scale. We focus the paper on the application of the workflow to the Green River Site in Utah. This is a rare case of leakage from a natural CO2 reservoir, where CO2 (dissolved or gaseous) migrates along two fault zones to the surface. This site provides a unique opportunity to understand CO2 leakage mechanisms and volumes along faults, because of its extensive characterisation including a large dataset of present-day CO2 surface flux measurements as well as historical records of CO2 leakage in the form of travertine mounds. When applied to this site, our methodology predicts leakage locations accurately and, within an order of magnitude, leakage rates correctly without extensive history matching. Subsequent history matching achieves accurate leak rate matches within a-priori uncertainty ranges for model input parameters.

Characteristics and implication of multilayer dawsonite in heterogeneity reservoir of the Honggang anticline, southern Songliao Basin, NE China

Reservoir heterogeneity is one of the key factors regarding the long-term fate of the injected CO2. Natural CO2 reservoir and ancient CO2-bearing reservoir is a natural analog to investigate the influence of reservoir heterogeneity on the migration of CO2 and CO2-rock interaction with geological timescale. Dawsonite cements are detected in both sandstone and mudstone of the Upper Cretaceous Qingshankou reservoir in Honggang anticline of the southern Songliao Basin, China. Here, we present results of a petrographic characterization of this reservoir based on polarizing microscope, X-ray diffraction, and fluid inclusion data. These data were used to identify the vertical distribution characteristic of dawsonite and to identify the migration characteristics for the supercritical CO2 in heterogeneity reservoir. Our analytical results show that as the “CO2 trace mineral,” dawsonite appears as multilayered zones of cementation that are separated by mudstone interlayers. These multilayered dawsonite could be one of the geological produces for supercritical CO2 flooding through the heterogeneous rock, acting as the lateral migration and upward diffusion. Supercritical CO2 could move through the thinner mudstone interlayer, with the product of dawsonite developing in the mudstone as its “footprint,” although the vertical distance of diffusion in low-permeability caprock is limited. Combined with the truth that most of the present CO2 gas reservoirs (in K1q4) are in the deeper layers than the dawsonite-bearing sandstone (K1q4-K2y1) (developed in non-CO2 reservoir), we can deduce that CO2 was at some time abundant in the Honggang anticline but had now part of CO2 been migrated, with the other part consumed by the reaction with the primary rock and captured as new carbonate minerals. The dawsonite-bearing sandstones also record a sequence of hydrocarbon filling events. Combined with the truth that the injection time of CO2 is later than that of hydrocarbon, the early hydrocarbon should be deasphalted by the injection and migration of mantle CO2. Therefore, CO2 could also be stored as long-term carbonate minerals after the termination of a CO2-EOR project.

A study of natural analogues for predicting the performance of a CO2 geological storage: the experience from a natural CO2 reservoir (Gañuelas-Mazarrón Tertiary Basin, SE Spain)

In the framework of a Spanish project focused on carbon capture and storage technologies, the Ganuelas-Mazarron Tertiary Basin (SE Spain) was studied as a natural analogue of a CO2 reservoir affected by anthropogenic leakages. It has been accepted that the main objective of natural analogue studies is to predict the long-term performance of a natural CO2 reservoir to be extrapolated to the operation of a CO2 deep geological storage, but these studies can also provide valuable information to select a site for CO2 storage. Thus, the comprehensive study performed in this Spanish basin has allowed the establishment of a guide to be applied to other similar natural systems with deep saline aquifers that are able to store CO2. This guide comprises 5 phases: (1) the compilation of existing information from the site; (2) the geological and structural study of the natural CO2 reservoir; (3) the characterisation of the main components (waters–rocks–gases) of the natural CO2 reservoir; (4) the identification of analogies between the natural CO2 reservoir and a potential site for CO2 geological storage; and (5) the implications for the long-term behaviour and safety of a CO2 storage system. Whilst the three first stages are well known since they are exclusively focused on the site characterisation, the latter two are poorly developed. For this reason, it has been considered convenient to go deeper into both the identification of analogies and the assessment of their performance in storing CO2. The main results of this study are aimed at elaborating a practical guide for regulatory agencies that are responsible for making decisions about sites that have been selected for anthropogenic CO2 geological storage.

Stress field orientation controls on fault leakage at a natural CO<sub>2</sub> reservoir

Abstract. Travertine deposits present above the St. Johns Dome natural CO2 reservoir in Arizona, USA, document a long (>400 kyr) history of surface leakage of CO2 from a subsurface reservoir. These deposits are concentrated along surface traces of faults, implying that there has been a structural control on the migration pathway of CO2-rich fluids. Here, we combine slip tendency and fracture stability to analyse the geomechanical stability of the reservoir-bounding Coyote Wash Fault for three different stress fields and two interpreted fault rock types to predict areas with high leakage risks. We find that these areas coincide with the travertine deposits on the surface, indicating that high-permeability pathways as a result of critically stressed fracture networks exist in both a fault damage zone and around a fault tip. We conclude that these structural features control leakage. Importantly, we find that even without in situ stress field data, the known leakage points can be predicted using geomechanical analyses, despite the unconstrained tectonic setting. Whilst acquiring high-quality stress field data for secure subsurface CO2 or energy storage remains critical, we shown that a first-order assessment of leakage risks during site selection can be made with limited stress field knowledge.

Effective stress constraints on vertical flow in fault zones: Learnings from natural CO2 reservoirs

Some fault zones leak vertically to the ground surface or seafloor, whereas most others remain naturally sealed. Understanding the factors that cause this leakage is essential for predicting and preventing such leakage for both conventional reservoir development and subsurface CO2 storage. This study, a comparison of leaking and nonleaking natural CO2 gas accumulations, provides such constraints. We compare and contrast trap configurations, fluid pressures, and stress states for several natural CO2 accumulations from the Colorado Plateau. Extensive surface geologic data are integrated with subsurface data from a large suite of groundwater and hydrocarbon wells. Leakage of CO2 is documented by geochemical surveys and the occurrence of extensive travertine deposits. The leakage occurs exclusively in fault fracture damage zones where the total fluid pressure reduces the minimum horizontal effective stress to approximately zero. These results are consistent with natural and accidentally induced fault seeps from some deep-water hydrocarbon reservoirs. These criteria can be used to evaluate the potential for fault zones to provide vertical leakage pathways and loss of fluid containment.

Current travertines precipitation related to artificial CO2 leakages from a natural reservoir (Gañuelas-Mazarrón Tertiary Basin, SE Spain)

In the framework of a natural CO2 reservoir with CO2 leakages as an analogue of a failed CO2 deep geological storage, the current precipitation of travertines and the associated upwelling of CO2-rich saline groundwater were analysed. This natural analogue is located in the Gañuelas-Mazarrón Tertiary Basin (SE Spain). The study comprises of the chemistry of both groundwater and travertines, including stable isotopes, mineralogy and petrography of the travertines, all this performed after a review of the geology of the basin. In this sense, the basin gathers the main features of a safe natural CO2 reservoir in a deep saline aquifer sealed by a thick marl formation. The aquifer was artificially perturbed by the drilling of wells, inducing the travertines precipitation at these water discharge points. Groundwater is saline, slightly acid, oversaturated in aragonite and calcite and with significant concentrations of heavy elements, some of them toxic. From an isotopic viewpoint, the relative constant δ13C-DIC values suggest that carbon is mainly inorganic in origin with minor organic and mantle contributions. Travertines are basically composed of aragonite or calcite, their precipitation being controlled by a sudden CO2 degassing and minor biological activity. Their δ13C signatures indicate that carbon mainly has an inorganic origin, although some contribution of organic carbon must be considered as well. Furthermore, these carbonate deposits did not precipitate in isotopic equilibrium, as determined by δ18O values. Finally, it is suggested that the appearance of travertines along with their carbon isotopic signatures represent efficient tools for detecting CO2 leakages from any CO2 storage site.

Prediction of CO2 storage site integrity with rough set-based machine learning

CO2 capture and storage (CCS) and negative emissions technologies (NETs) are considered to be essential carbon management strategies to safely stabilize climate. CCS entails capture of CO2 from combustion products from industrial plants and subsequent storage of this CO2 in geological formations or reservoirs. Some NETs, such as bioenergy with CCS and direct air capture, also require such CO2 sinks. For these technologies to work, it is essential to identify and use only secure geological reservoirs with minimal risk of leakage over a timescale of multiple centuries. Prediction of storage integrity is thus a difficult but critical task. Natural analogues or naturally occurring deposits of CO2, can provide some information on which geological features (e.g., depth, temperature, and pressure) are predictive of secure or insecure storage. In this work, a rough set-based machine learning (RSML) technique is used to analyze data from more than 70 secure and insecure natural CO2 reservoirs. RSML is then used to generate empirical rule-based predictive models for selection of suitable CO2 storage sites. These models are compared with previously published site selection rules that were based on expert knowledge.

CO2 leakage detection in the near-surface above natural CO2-rich water aquifer using soil gas monitoring

Conventional soil gas monitoring methods were applied above a natural low-level CO2 reservoir to locate natural CO2 leakage and assess effectiveness in monitoring geological carbon storage sites. The concentrations of the soil gas (N2, O2, and CO2) and carbon-13 isotopes of soil CO2 (δ13CCO2) were determined for ninety-four soil gas samples that were collected at a depth of ∼60 cm. The CO2 flux was also measured at the same sampling locations. The 93 soil gas samples were divided into two groups: Group A with low soil CO2 concentrations and high δ13CCO2, which was influenced by the atmospheric air, and Group B with high soil CO2 concentrations and low δ13CCO2, which originated from microbial processes. Sample M17, which was close to a CO2-rich water well, had an exceptionally high soil CO2 (36.0% v/v), δ13CCO2 (-5.7‰), and flux (546.2 g/m2/d), indicating geogenic CO2 inflow to the soil layer and discharge through the surface. This study shows that conventional soil gas monitoring methods are useful for locating CO2 leakage. A dense grid soil CO2 sampling near wells and periodic investigations are crucial for further understanding of the CO2 flow paths in the soil layer.

Numerical simulation of calcite vein formation and its impact on caprock sealing efficiency – Case study of a natural CO2 reservoir

For the long-term CO2 geological storage, the evolution of the caprock sealing efficiency has received increasing attention. In this paper, the Huangqiao CO2 gas field in Jiangsu Province, China, where the calcite veins have been found in the lower part of mudstone caprock, is considered as a natural analogue site for CO2 geological sequestration (CCS). To ascertain the dynamic formation process of calcite vein and its impact on the evolution of caprock sealing efficiency, a one-dimensional model was designed to represent the fractured reservoir-caprock system. Numerical simulations were performed using the multiphase reactive transport program TOUGHREACT. Sensitivity analyses of fracture permeability and calcite reaction rate were made. The simulation results illustrate that calcium bicarbonate decomposes to form calcium carbonate and release CO2 from solution due to the pressure decay as the CO2-rich fluids migrate upwards along the fracture. The formation of calcite vein decreases the porosity and permeability significantly, which can enhance the integrity and sealing efficiency of caprock. Sensitivity analyses indicate that the formation of calcite vein is facilitated by the fast fluid flow, and calcite vein tends to form in the vicinity of reservoir-caprock interface under the slow-flow condition as the decrease of fracture permeability. Information currently available in Huangqiao CO2 gas field and some other area describing the formation of calcite vein shows good agreement with our simulation results. The mudstone caprock with fractures and faults is able to keep CO2 from leaking for a long time as the case of Huangqiao area. The methods and analyses presented here may be useful for CO2 storage sites with similar conditions.

Flue gas injection for EOR and sequestration: Case study

The combination of carbon dioxide enhanced oil recovery (CO2-EOR) and permanent CO2 storage in mature oil reservoirs has the potential to provide a critical near-term solution for reducing greenhouse gas (GHG) emissions. This solution involves the combined application of carbon capture and storage from power generation and other industrial facilities with CO2-EOR. In order to reduce CO2 capture costs flue gas, which consists mainly of N2 and CO2, injection has been proposed. The main aim of this research is to investigate flue gas injection in a mature oil field located in Turkey where CO2 EOR had been applied between 2003 and 2012. Injected CO2 was produced from a nearby small natural CO2 reservoir with limited resource. Due to the availability of nearby flue gas source (cement factory) and a pipeline for gas transportation, which was built to transport natural gas from the oil field to cement factory, there is a huge opportunity to decrease project costs. A 3D compositional simulation model was built after a detailed fluid characterization. After history matching 31 years of production, injection, saturation and pressure history, a comparative study was conducted to examine the efficiency of flue gas injection compared to CO2 injection for simultaneous EOR and storage purposes. Storage capacity of the oil field as well as the contribution of raw flue gas injection and CO2 injection to oil recovery were studied. Effect of injected gas type, gas solubility and operating parameters on storage and recovery were investigated. Results showed that pure CO2 injection leads to higher oil recovery and CO2 storage, if injection continued for at least 25 years. Before this threshold injection time, flue gas injection and pure CO2 injection resulted in comparable oil recoveries. It was also concluded that pressurizing the reservoir with raw flue gas injection followed by pure CO2 injection may improve the project economics.

Validating Reactive Transport Models of CO2-brine-Rock Reactions in Caprocks Using Observations from a Natural CO2 Reservoir

Storage of anthropogenic CO2 in geological formations relies on impermeable caprocks as the primary seal preventing buoyant super-critical CO2 escaping. Although natural CO2 reservoirs demonstrate that CO2 may be stored safely for millions of years, uncertainty remains in predicting how caprocks will react with acid CO2-bearing brines. This uncertainty poses a challenge to the assessment of carbon capture and storage schemes. Prediction of caprock behaviour is based primarily on theoretical modelling and laboratory experiments. However, the reactive transport phenomena cannot be reproduced in laboratory experiments over sufficient timescales, theoretical models need calibration against observational data and existing studies on natural caprocks have not resolved mineral reactions. Here we report a detailed description of a stacked sequence of CO2 reservoir-caprock systems exposed to CO2-rich fluids over ∼ 105 years, a time-scale comparable with that needed for effective geological carbon storage. Fluid-mineral reactions in the base of multiple caprocks is driven by diffusion of CO2 and minor H2S from the underlying reservoirs. The reactions include dissolution of hematite, dolomite and K-feldspar and precipitation of Fe-bearing dolomite, gypsum, pyrite and illite over centimetre length-scales. The mineral dissolution reactions generate transient increases in porosity, as determined by neutron scattering measurements, but the propagation of mineral reaction fronts is retarded by the reaction stoichiometry and mineral precipitation. Modelling of the mineral reaction fronts shows that the alteration is sluggish, developing over a >104 year period. The results attest to the significance of transport-limited reactions to the long-term integrity of sealing behaviour in caprocks exposed to CO2.

Stable Isotope Compositions of Different Mineral Phases Found in a Natural CO2-reservoir (NW-Hungary): Implication for their Origin

Stable isotope systems provide exceptional insight into fluid-solid interactions occurring in the sub-surface. We provide detailed insight into the stable isotope distribution of carbonate minerals in a natural CO2 reservoir system from Mihályi-Répcelak area, NW-Hungary. Several types of measurements and calculations have been applied for the estimation of CO2 and H2O isotopic composition in equilibrium with dawsonite. The estimated δ13C of CO2 exhibit values around -4.5 to -2.6 ‰ overlapping with assumed magmatic values and the presently measured gas data confirming magmatic origin, whereas we may assume that the water present during carbonate formation likely had meteoric origin.

Natural CO 2 sites in Italy show the importance of overburden geopressure, fractures and faults for CO 2 storage performance and risk management

Abstract The study of natural analogues can inform the long-term performance security of engineered CO 2 storage. There are natural CO 2 reservoirs and CO 2 seeps in Italy. Here, we study nine reservoirs and establish which are sealed or are leaking CO 2 to surface. Their characteristics are compared to elucidate which conditions control CO 2 leakage. All of the case studies would fail current CO 2 storage site selection criteria, although only two leak CO 2 to surface. The factors found to systematically affect seal performance are overburden geopressure and proximity to modern extensional faults. Amongst our case studies, the sealing reservoirs show elevated overburden geopressure whereas the leaking reservoirs do not. Since the leaking reservoirs are located within <10 km of modern extensional faults, pressure equilibration within the overburden may be facilitated by enhanced crustal permeability related to faulting. Modelling of the properties that could enable the observed CO 2 leakage rates finds that high-permeability pathways (such as transmissive faults or fractures) become increasingly necessary to sustain leak rates as CO 2 density decreases during ascent to surface, regardless of the leakage mechanism into the overburden. This work illustrates the value of characterizing the overburden geology during CO 2 storage site selection to inform screening criterion, risk assessment and monitoring strategy.