Geological Storage Of Carbon Dioxide Research Articles

Robust machine learning models of carbon dioxide trapping indexes at geological storage sites

Geological carbon dioxide (CO2) storage (GCS) in saline aquifers has been recognized as a promising way to slow down global CO2 emissions. The residual and solubility trapping efficiency of CO2 in saline aquifers play a crucial role in monitoring CO2sequestration performance. Due to this fact, the goal of this paper is to determine the effectiveness of three robust machine learning (ML) models — a general regression neural network (GRNN) model and two multilayer perceptron (MLP) models respectively optimized with the Levenberg-Marquardt algorithm (LMA) and Bayesian Regularization (BR) — in predicting the residual trapping index (RTI) and solubility trapping index (STI) of CO2 in saline aquifers. A comprehensive and wide-ranging dataset was compiled from the literature, including over 1,910 simulation samples from numerous CO2 field models. The predicted results revealed that all the proposed ML techniques have an excellent agreement with simulation data. In addition, the error analyses and a comparison of statistical indicators indicated that the GRNN model was more accurate than the MLP-LMA and MLP-BR models as well as two ML models developed in previous studies. The GRNN model exhibited overall coefficient of determination (R2) values of 0.9995 and 0.9998 and average absolute relative error (ARE) percentages of 0.7413% and 0.2950% for RTI and STI, respectively.Furthermore, a trend analysis confirmed the robustness of the GRNN model, as predicted and simulated RTI and STI exhibited strong overlap under four different sets of input parameters. Moreover, the Williams plot reveals that the validity of GRNN model was affirmed, and only a small suspected data was detected from the collected database. Therefore, the GRNN model proposed in this study could serve as a template for evaluating the feasibility of future GCS projects in saline aquifers. Lastly, the findings of this study can help better understanding the promising of machine learning techniques for predicting CO2 trapping efficiency in geological storage sites.

Study on the Influential Factors of CO2 Storage in Low Permeability Reservoir

As the demands of tight-oil Enhanced Oil Recovery (EOR) and the controlling of anthropogenic carbon emission have become global challenges, Carbon Capture Utilization and Sequestration (CCUS) has been recognized as an effective solution to resolve both needs. However, the influential factors of carbon dioxide (CO2) geological storage in low permeability reservoirs have not been fully studied. Based on core samples from the Huang-3 area of the Ordos Basin, the feasibility and influential factors of geological CO2 sequestration in the Huang-3 area are analyzed through caprock breakthrough tests and a CO2 storage factor experiment. The results indicate that capillary trapping is the key mechanism of the sealing effect by the caprock. With the increase of caprock permeability, the breakthrough pressure and pressure difference decreased rapidly. A good exponential relationship between caprock breakthrough pressure and permeability can be summarized. The minimum breakthrough pressure of CO2 in the caprock of the Huang-3 area is 22 MPa, and the breakthrough pressure gradient is greater than 100 MPa/m. Huang-3 area is suitable for the geological sequestration of CO2, and the risk of CO2 breakthrough in the caprock is small. At the same storage percentage, the recovery factor of crude oil in larger permeability core is higher, and the storage percentage decreases with the increase of recovery factor. It turned out that a low permeability reservoir is easier to store CO2, and the storage percentage of carbon dioxide in the miscible phase is greater than that in the immiscible phase. This study can provide empirical reference for caprock selection and safety evaluation of CO2 geological storage in low permeability reservoirs within Ordos Basin.

Laboratory simulation and dynamics study of carbon dioxide geological storage system

In recent years, the issue of carbon dioxide disposal has become a national hot issue, and China has pledged to the international community to achieve the goal of carbon neutrality by 2060. In this paper, the relationship between the water-rock reaction rate of different ores and temperature and alkalinity is first studied by consulting relevant data. It is found that the reaction rate of quartz increases with the increase of temperature under neutral conditions, and the reaction rate of manganese-free ore increases with the alkalinity. At the same time, the kinetic parameters of the water-rock reaction were determined. Secondly, the underground storage model of carbon dioxide is established by using the law of conservation of mass and Darcy's law, and a case of solving the model is given. Finally, the sensitivity analysis of the model was carried out, and it was found that the model was not sensitive to carbon dioxide density and flow, but was more sensitive to soil porosity, and the sensitivity first decreased, then increased and finally stabilized.

Machine Learning Applications for Geologic Data Integration and Operational Data Analysis in Geologic Carbon Dioxide Storage Systems

Machine Learning Applications for Geologic Data Integration and Operational Data Analysis in Geologic Carbon Dioxide Storage Systems

Effect of competitive adsorption on the deformation behavior of nanoslit-confined carbon dioxide and methane mixtures

Understanding the behaviors of nanoslit-confined carbon dioxide and methane mixtures is of great importance in geological storage of carbon dioxide (CO2) and extraction of methane (CH4) from shale/coalbeds. Herein, the effects of pore width, bulk mixture composition, and geographic depth on the mixture adsorption and pore deformation tendency are studied by using the classical density functional theory. The solvation pressure against pore width shows an oscillating distribution, indicating a deformation transition from expansion to contraction in nanopores. A high recovery ratio of CH4 can be found in small pores at low temperatures and under high bulk pressure. For the 0.68 nm pore, a remarkably high optimal recovery ratio is identified at the geographic depth of about 0.2 km, while for the pores with pore width of 0.9–1.2 nm a modest optimal recovery ratio locates at the depth of about 0.5–1.0 km. This work provides a thorough understanding of the adsorption and deformation behavior of slit-confined mixtures.

Assessment of integrated CO2 geologic storage and geothermal harvest in a semi-closed thin reservoir

CO2 plume geothermal (CPG) production built on the ongoing or completed Carbon Dioxide (CO2) geological storage (CGS) offers an emerging technique to harvest non-carbon renewable energy and offset CGS cost. Several studies on integrated CGS and CPG considered traditional 5-spot well placement in large-scale and thick saline formations with open boundaries. Very limited studies have been conducted on fault-compartmentalized, inclined thin reservoirs, which are widely available in oil/gas fields. Critical pressure management and risk of fault leakage have to be carefully evaluated dealing with such kind of geological structures. The aim of this study is to fill in this knowledge gap in the field of integrated CGS and CPG. A suite of model simulations is designed and experimented to assess CO2 sequestration and circulation in a fault-reservoir system under three levels of critical overpressure. Sensitivity of performance indictors to well space and circulation rate are quantitatively and continuously evaluated in their ranges using response surface method. Analysis of response surfaces yields a simple but efficient guidance for geothermal field planner and operator to find optimal well placement and operation scheme according to the priority of goals, including maximal energy production, desired heat energy capacity, expected lifespan.

Micro CT and Experimental Study of Carbonate Precipitation from CO2 and Produced Water Co-Injection into Sandstone

Carbon dioxide geological storage involves injecting captured CO2 streams into a suitable reservoir. Subsequent mineral trapping of the CO2 as carbonate minerals is one of the most secure forms of trapping. Injection of CO2 dissolved in water or co-injection of CO2 with water may enhance trapping mechanisms. Produced waters are already re-injected into reservoirs worldwide, and their co-injection with CO2 could enhance mineral trapping in low reactivity rock by providing a source of cations. Sandstone drill core from a reservoir proposed for CO2 storage was experimentally reacted with supercritical CO2 and a synthetic produced water. Micro computed tomography (CT), QEMSCAN, and SEM were performed before and after the reaction. The sandstone sample was predominantly quartz with minor illite/muscovite and kaolinite. The sandstone sub-plug micro-CT porosity was 11.1% and 11.4% after the reaction. Dissolved Ca, Mg, and Sr decreased during the reaction. After the reaction with CO2 and synthetic produced water, precipitation of crystalline carbonate minerals calcite and dolomite was observed in the pore space and on the rock surface. In addition, the movement of pore filling and bridging clays, as well as grains was observed. Co-injection of CO2 with produced waters into suitable reservoirs has the potential to encourage CO2 mineral trapping.

Quantitatively determine CO2 geosequestration capacity in depleted shale reservoir: A model considering viscous flow, diffusion, and adsorption

Depleted hydrocarbon reservoirs have been gradually recognized as the potential candidates for geological storage of carbon dioxide due to their wide geographical spread and large storage capacity. Reliably assess CO2 geosequestration capacity (CGC) of depleted hydrocarbon reservoirs lays the foundation of CO2 long-term geosequestration security. In this study, a model, considering CO2 viscous flow, diffusion, and adsorption in shale reservoirs, is established to determine bottom-hole pressure during CO2 injection through a hydraulic fractured multiwell-pad. The computational efficient semi-analytical solution is obtained by superposition principle and Laplace numerical inverse technique. Applying the developed model, a workflow is accordingly proposed to evaluate CGC of depleted shale reservoirs. As a case verification, the calculation on the CGC of a depleted shale reservoir from Barnett Shale in Texas is conducted, which illustrates that its CGC reaches up to 3.8 × 1012m3 when the constrained injection pressure (CIP) is high. Moreover, sensitivity analyses suggest that most reservoir parameters exhibit ignorable impacts on CGC when CIP is low whereas their effects on CGC are significant at high CIP. For instance, for the low-CIP, CGC just increases by approximately 6.7% when adsorption index increases from 2.5 to 250. As for the high-CIP scenario, CGC significantly increases 164 times for the same adsorption index range. In contrast to reservoir parameters, engineering parameters generally show great impacts on CGC at low CIP whereas their effects on CGC are negligible when CIP is high. To be more specific, CGC increases by 2.42 times when injection rate ratio of two wells ranges from 8 to 0.5 under low-CIP condition whereas CGC increases just by 0.47 times when CIP is high. The findings obtained in this study pave the way for the long-term CO2 geosequestration in depleted hydrocarbon reservoirs with much less efforts.

An interval-parameter two-stage optimization model for CO2 collection, distribution, transportation, utilization, and storage planning

Geological carbon dioxide (CO2) utilization and storage have been widely recognized as one of the important options to deliver greenhouse gas emissions reduction. Reasonable planning is critical to promote CO2 utilization and storage. However, CO2 emissions gas collection exhibits a stochastic probability distribution, and CO2 utilization and storage features fluctuation demands, which have gone beyond current determine planning techniques. To fulfill the current research gap, this study develops an interval-parameter two-stage programming-based CO2 collection, distribution, transportation, utilization, and storage optimization model, integrating interval parameter planning and two-stage planning into a general framework. Therefore, the model can address uncertainties expressed as random probabilistic distributions and discrete intervals, tackle dynamic facilities capacity expansion issues, develop optimal predefined CO2 distribution policy, and generate recourse schemes to address gas shortage or gas surplus issues. The model is examined by a typical hypnotical case study in China. The results revealed that the model could generate a set of first-stage reasonable CO2 distribution and facilities capacity expansion schemes to maximum system benefits and the highest feasibility. Besides, a set of two-stage CO2 outsourcing purchases and facilities capacity expansion in reserve storage regions solutions were also generated to address the gas oversupplies and shortage issues. The modeling approach enriches the current CO2 utilization and storage distribution research content under multiple uncertainties.

Utility of natural and artificial geochemical tracers for leakage monitoring and quantification during an offshore controlled CO2 release experiment

To inform cost-effective monitoring of offshore geological storage of carbon dioxide (CO2), a unique field experiment, designed to simulate leakage of CO2 from a sub-seafloor storage reservoir, was carried out in the central North Sea. A total of 675 kg of CO2 were released into the shallow sediments (∼3 m below seafloor) for 11 days at flow rates between 6 and 143 kg d-1. A set of natural, inherent tracers (13C, 18O) of injected CO2 and added, non-toxic tracer gases (octafluoropropane, sulfur hexafluoride, krypton, methane) were used to test their applicability for CO2 leakage attribution and quantification in the marine environment. All tracers except 18O were capable of attributing the CO2 source. Tracer analyses indicate that CO2 dissolution in sediment pore waters ranged from 35 % at the lowest injection rate to 41% at the highest injection rate. Direct measurements of gas released from the sediment into the water column suggest that 22 % to 48 % of the injected CO2 exited the seafloor at, respectively, the lowest and the highest injection rate. The remainder of injected CO2 accumulated in gas pockets in the sediment. The methodologies can be used to rapidly confirm the source of leaking CO2 once seabed samples are retrieved.

Effects of the mechanical response of low-permeability sandstone reservoirs on CO2 geological storage based on laboratory experiments and numerical simulations

Carbon dioxide (CO2) geological storage (CGS) is an effective way for reducing greenhouse emissions. The injection of CO2 into the deep formation changes the pore pressure and effective stresses in the reservoir, thus leading to changes in stress-dependent porosity and permeability. These changes give feedback to the injection rate, migration, storage amount of CO2 in the target reservoir. In this study, we focus on the Liujiagou reservoir, one of the first demonstration CGS project in saline aquifers in the Ordos Basin, China. The mathematical model that defines the relationship between the permeability and the injection pressure (or effective stress) was obtained by laboratory experiments. On this basis, the permeability-stress law was successfully integrated into the thermo-hydro-mechanical (THM) coupled simulator TOUGH2Biot to simulate the feedback between the flow and mechanical response. The improved simulator was used to analyze the effects of reservoir mechanical response on CO2 geological storage efficiency. The modeling results indicated that the mechanical response of the reservoir had little effect on reservoir pore pressure and porosity, but it had a significant effect on reservoir permeability and the migration distance, injection rate, and total storage amount of CO2. The maximum increases in the lateral migration distance of CO2 caused by the reservoir mechanical response reached 13.1% using 5 MPa injection pressure. In addition, the total CO2 storage amount increased by 11.6% after 5 years of continuous CO2 injection. Furthermore, when the injection pressure was greater, the reservoir mechanical response had stronger enhancement effects on CGS. Overall, the results suggested that the reservoir mechanical response during CO2 injection was beneficial for increasing CGS efficiency and emphasized the importance of considering the mechanical response in CGS.

The preliminary selection of oil reservoir in Serbia for carbon dioxide injection and storage by a multicriteria decision-making approach: a case study

ABSTRACT One of the current prospective solutions that can contribute to significant carbon dioxide emission mitigation is carbon capture and storage in geological formations. The most challenging issue in underground storage is the provision of safe and long-term storage without possible carbon dioxide leakage. From the safety point of view, it is considered that the most appropriate geological formations for carbon dioxide storage are depleted hydrocarbon reservoirs or partially depleted oil reservoirs, where injection of carbon dioxide enhances oil recovery. This paper proposes a multicriteria decision-making model for preliminary selection of an oil reservoir in Serbia for carbon dioxide injection and storage. Applied multicriteria decision-making methods are ”Technique of order preference similarity to the ideal solution” (TOPSIS) and ”Multicriteria optimization and compromise solution” (VIKOR). In the analyzed multicriteria decision model three alternative oil reservoirs and seven criteria are considered. The evaluation and decision-making process presented in the study includes a selection of the geological formations for storing carbon dioxide and enhancing oil recovery, choosing the criteria and alternatives, the initial decision-making matrix development, weight criteria determination by entropy method, application of multicriteria decision-making methods for ranking alternatives, and comparison of applied methods results. The results of this study show that the same results are obtained by applying these two methods, i.e., oil reservoir A3 is the most appropriate candidate for application of carbon dioxide injection and geological storage.

Optimal selection of favorable areas for CO2 geological storage in the Majiagou Formation in the Ordos Basin

Carbon dioxide (CO2) geological storage (CGS) is considered as one of the feasible choices for large-scale CO2 emission reduction worldwide, and the primary issue in CGS is how to select areas favorable for storing CO2. The research conducted by Chinese scholars on CO2 geological storage in the Ordos Basin has mainly focused on numerical simulations of CO2 storage, the estimation of the CO2 storage capacity, and the CO2 storage mechanism. Few studies have been conducted on the selection of CO2 geological storage area, or even on a methodology for ranking CO2 geological storage sites in carbonate reservoirs. This study provides a reference for the ranking of CGS areas in carbonate reservoirs. First, from the geological view of CO2 storage reservoir, logging data and core petrographic analyses with cast thin sections, scanning electron microscopy and formation water salinity tests were used to systematically investigate the reservoir type, lithology, porosity, permeability, burial depth, thickness, temperature, and pressure conditions, and water salinity of the Majiagou formation. Second, from the perspective of CO2 storage safety, literature research, and seismic interpretation data were used to investigate the sealing performance of the strata overlying the Majiagou Formation and its related fault system in detail. Third, from the economic perspective of CO2 storage, considering the distance from the source of the CO2 emissions, the extent of the regional exploration, and the degree of the influence of CO2 storage on the exploitation of other mineral resources, the CO2 storage areas in the Majiagou Formation in the Ordos Basin were prioritized. The results show that (1) the Wushenqi-Jingbian-Yan'an karst slope area (I1) is the best CO2 geological storage area, (2) the Yulin-Mizhi karst basin area (I2) is a favorable area for CGS in the Ordos Basin. (3) A site ranking methodology for CGS is also proposed, providing a reference for the selection of CO2 geological storage areas in carbonate reservoirs based on the technical, safety, and economic feasibility of the CGS.

Three-Dimensional Imaging of Dissolution-Driven Convection in Simple Porous Media Using X-ray CT Scanning

Motivated by geological carbon dioxide (CO2) storage and the associated process of CO2 convective mixing in brine, we present an experimental method to visualize dissolution-driven convection in a three-dimensional porous medium. Owing to the difficulty of imaging the time-dependent convective process within an opaque medium, experiments so far have largely focused on two-dimensional systems. However, this imposes a strong restriction on the lateral spreading of the plumes. To explore the flow pattern within a three-dimensional medium, we present an experimental procedure employing X-ray computed tomography that enables the visualization of the spatial and temporal evolution of the mixing process non-invasively. To mimic the dissolution of CO2 in brine, we use potassium iodide (KI) in water. Here, we show the results with high spatial and temporal resolution for an experiment with a homogeneous packing of glass beads (Ra=5300). We discuss the evolution of the average solute mass fraction, compare it to numerical results of a purely diffusive process and report a strong enhancement of the dissolution process when convection dominates over diffusive mass transfer effects.

Carbonate Caprock–Brine–Carbon Dioxide Interaction: Alteration of Hydromechanical Properties and Implications on Carbon Dioxide Leakage

Summary Caprocks play a crucial role in the geological storage of carbon dioxide (CO2) by preventing its escape and thus trapping it into underlying sequestering reservoirs. An evaluation of interaction-induced alteration of the hydromechanical properties of caprocks is essential to better assess the leaking risk and injection-induced rock instability, thus ensuring a long-term viability of geological CO2 storage. We study the changes in minerals, nanopores, elastic velocities, and mechanical responses of a carbonate caprock caused by rock–water/brine–CO2 interaction (CO2 pressure: ≈12 MPa; 50°C). Before the interaction, the total and accessible porosities are 1.6 and 0.6%, respectively, as characterized by the small-angle neutron scattering (SANS) technique. SANS results show that the total porosity of the carbonate caprock increases, apparently because of rock–brine–CO2 interaction, and the increasing rate rises as brine concentration increases (2.2% for 0 M NaCl, 2.6% for 1 M NaCl, and 2.7% for 4 M NaCl). The increase in total porosity is due to the dissolution of calcite, which tends to enlarge accessible pores (by 0.8 to 1.2%) while slightly decreasing the inaccessible pores (by 0.1–0.2%). Under a CO2–acidified water environment, the compressional-wave (P-wave) and shear-wave (S-wave) velocities (5536.7 and 2699.7 m/s) of a core sample containing natural fractures decrease by 8.5 and 8.1%, respectively, whereas both P- and S-wave velocities (6074.1 and 3858.8 m/s) for an intact sample show only ≈0.5% decreases. The interaction also causes more than 50% degradation of the uniaxial compressive strength for the core sample with natural fractures. X-ray microcomputed tomography experiments on three tiny cores (diameter: 1 mm) after 5-day treatment with CO2 (12 MPa) also show that matrix erosion occurs under CO2–acidified water environment but barely occurs without a direct contact with liquid water. Our study suggests that the hydromechanical properties of carbonate caprocks could evolve over the long-term CO2–brine invasion, and it is critical to monitor the CO2–acidified brine interface for a better and long-term evaluation of the caprock integrity.

Carbon Storage Potential of North American Oil & Gas Produced Water Injection with Surface Dissolution

Carbon dioxide (CO2) geological storage traditionally involves capturing a CO2 stream from a point source such as a power station or from cement, steel, or natural gas processing plant, transporting it and compressing it, prior to injection as a supercritical phase into a suitable geological reservoir overlain by a cap-rock or seal. One of the main perceived risks in CO2 geological storage is migration or leakage of the buoyant CO2 stream through the seal, via faults or fractures, or other migration out of the storage complex. Injection of CO2 dissolved in water may be one solution to mitigate the leakage risk. This approach could take advantage of large volumes of wastewater already being reinjected into saline aquifers worldwide but particularly in North America, thus reducing costs. This study examines the potential to “piggyback” off the existing wastewater injection industry as a novel carbon storage option.

Comparative Analysis of Six Geologic Sequestration Methods

With the extensive use of fossil fuels[1] since the advent of the industrial age, the amount of carbon dioxide emitted is also increasing dramatically, which has also led to a severe greenhouse effect[2]. The method of carbon capture and carbon sequestration[3] proposed in recent years is a good way to deal with too much carbon dioxide. However, Carbon Sequestration is a new idea without enough practice and verification, and its development is not perfect yet. This paper reviews six commonly used geological Carbon dioxide storage methods and compares the advantages and disadvantages of them. It can be concluded that hydrodynamic force sequestration is the most suitable, effective and promising method of Carbon sequestration[4]. This study aims to provide scientific suggestions and theoretical basis for the future development of carbon sequestration, and it also provides effective help and support for environmental protection.

CCUS Progress in South Africa

Carbon Capture and Storage (CCS) has been identified as one of the CO2 emissions reduction mechanisms that could assist South Africa to meet its emissions reduction targets. The technology is part of the various South Africa’s emission reduction plans such as the Integrated Resources Plan (IRP) and National Development Plan (NDP). CCS is further identified as one of the National Flagship Priority Programme in the National Climate Change Response White Paper. The initial focus for CCS in South Africa was on geological storage. Without safe and permanent storage, CCS would not be a viable option to mitigate CO2 emissions. Following the publication of the Atlas on Geological Storage of Carbon Dioxide in South Africa, the South African government through SANEDI/SACCCS initiated a Pilot CO2 Storage Project (PCSP). The project commenced by analysing existing onshore geological data in Zululand and Algoa Basins. The decision was subsequently made to focus on the Zululand Basin. This decision was informed by time, cost, and geology considerations. The PCSP is currently delayed for various reasons. Consequently, the opportunity arose to use that time to apply new techniques, previously not available, to analyse the existing geological data in the KZN Basin, the outcome of which was the identification of two prospective injection sites. The current work is directed to characterising these two sites. With the PCSP well advanced, SANEDI is now incorporating other aspects of carbon capture, utilisation and storage (CCUS) into the programme, such as carbon capture, carbon utilisation and mineral carbonisation. The updated Roadmap will be presented as well as details of the PCSP. More recently, the Minister of Mineral Resources and Energy has approved the transfer of the CCUS Programme from SANEDI to the Council for Geosciences (CGS).

Carbon Capture & Storage: Rock Experimental Characterization & Modelling Prospective

Geological storage of carbon dioxide is one of the options of greenhouse gas mitigation as it reduces the release of CO2 to the atmosphere. Eni is a major energy company in which decarbonization plays an essential role in its vision for a future with zero net emissions. H field carbon storage project comes in line with Eni strategy of carbon neutrality by 2050. Depleted gas fields are among the most suitable candidates for CO2 sequestration, with well-known high quality reservoir characteristics and good sealing. H is a depleted offshore gas field located in the North Sea; it has two main reservoirs: H1 and H2. Due to the massive size of both reservoirs, well-known reservoirs’ characterization, good reservoirs’ petrophysics, and the existence of thick and continuous cap layers (C1 & C2), H1 and H2 reservoirs have been nominated to be good candidates for a carbon sequestration project. The study objective is to build comprehensive mineralogical and geochemical models able to capture the physical and the chemical phenomena occurring in the short – medium – long terms after the CO2 injection in H1 and H2 formations. The proposed workflow relies on the following procedure: 1. laboratory experimental analyses (SEM-EDX, XRD, XRF) on core samples 2. data elaboration and integration 3. conceptual geological-geochemical models’ definition 4. 0D static batch models a. equilibrium approach b. kinetic approach Step 1, 2 and 3 are aimed at obtaining the mineralogical model, with attention devoted to the presence of the Fe-bearing minerals. In step 4, the rock-formation water geochemical system consistence is preliminary checked by performing a sequence of 0D equilibrium models with PHREEQC-V3 code, (USGS, 1999), allowing primary evaluations on mineral phases chemical stability (dissolution/precipitation). This step is also needed for obtaining a synthetic formation water composition at the equilibrium with the mineralogical model used in the subsequent reactive transport models (RTM), and to validate new-estimated site-specific minerals thermochemical parameters. Then, the CO2 injection is preliminary simulated by means of 0D kinetic models to assess the main acting geochemical processes triggered by rock-brine-CO2 interaction. The results show that, at the conditions considered in the project, the rock petrophysical properties (e.g. porosity) alteration does not seem to be an issue. However, the main criticalities/uncertainties might be related to the Fe-bearing minerals (carbonates, micas and clays) chemical behavior in presence of CO2. As a final remark, the simulation results obtained in this work cannot be regarded as values of general validity because they depend on the characteristics assigned to each reservoir model. Nevertheless, the study provides a novel geochemical modelling procedure, which implies building a detailed geochemical conceptual model modelled by means of a complex kinetic reaction network to simulate the mineralogical alterations. The presented procedure can be followed to preliminary assess the geochemical short- and long-term risks for a given carbon storage project.

The CSIRO In-Situ Laboratory: a field laboratory for derisking underground gas storage

The industry in western Australia has committed to addressing their carbon emissions in response to the governments aspiration of net zero greenhouse gas emissions by 2050. Natural gas will play an important role in the transition to a fully renewable energy market but will require the geological storage of carbon dioxide to limit emissions and enable the production of blue hydrogen. Underground storage of energy in general (e.g. natural gas, hydrogen, compressed air) will be needed increasingly for providing options for temporary storage of energy from renewable resources and for energy export. Storage operations would need to provide adequate monitoring systems in compliance with yet to be defined regulations and to assure the public that potential leakage or induced seismicity could be confidently detected, managed and remediated. The In-Situ Laboratory in the southwest of western Australia was established in 2019 as a research field site to support low emissions technologies development and provides a unique field site for fluid injection experiments in a fault zone and testing of monitoring technologies between 400m depth and the ground surface. The site currently consists of three wells instrumented with fibre optics, pressure, temperature and electric resistivity sensors as well as downhole geophones. A controlled release of CO2 and various water injection tests have demonstrated the ability to detect pressure and temperature effects associated with fluid injection. Future experiments planned at the site will help in improving the sensitivity of monitoring technologies and could contribute to defining adequate monitoring requirements for carbon dioxide, hydrogen and other energy storage operations.