CO2 In Aquifers Research Articles

Optimization of Offshore Saline Aquifer CO2 Storage in Smeaheia Using Surrogate Reservoir Models

Machine learning-based Surrogate Reservoir Models (SRMs) can replace/augment multi-physics numerical simulations by replicating the reservoir simulation results with reduced computational effort while maintaining accuracy compared with numerical simulations. This research will demonstrate SRMs’ potential in long-term simulations and optimization of geological carbon storage in a real-world geological setting and address challenges in big data curation and model training. The present study focuses on CO2 storage in the Smeaheia saline aquifer. Two SRMs were created using Deep Neural Networks (DNNs) to predict CO2 saturation and pressure over all grid blocks for 50 years. 18 million samples and 31 features, including reservoir static and dynamic properties, build the input data. Models comprise 3–5 hidden layers with 128–512 units apiece. SRMs showed a runtime improvement of 300 times and an accuracy of 99% compared to the 3D numerical simulator. The genetic algorithm was then employed to determine the optimal rate and duration of CO2 injection, which maximizes the volume of injected CO2 while ensuring storage operations’ safety through constraints. The optimization continued for the reproduction of 100 generations, each containing 100 individuals, without any hyperparameter tuning. Finally, the optimization results confirm the significant potential of Smeaheia for storing 170 Mt CO2.

A parallel compositional reservoir simulator for large-scale CO2 geological storage modeling and assessment

Storing CO2 in deep aquifers and depleted gas reservoirs is an effective way to achieve carbon neutrality. However, the numerical simulation of CO2 storage in these formations is challenging due to the complexity of gases-brine systems. The number of gas species included in the gases-brine fluid models of existing simulators cannot meet the rapidly evolving CO2 sequestration scenarios. To address this intricate issue, we developed a three-dimensional fully implicit parallel CO2 geological storage simulator (PRSI-CGCS) on distributed-memory computers based on our in-house parallel platform. This simulator uses a compositional fluid model with a diverse range of gas species, including CO2, C1 ~ C3, N2, H2S, as well as newly added gases H2 and O2, which may be encountered in geological CO2 storages. Besides, we provide more suitable scaling factors for different gases in the stability analysis bypassing (SAB) method to accelerate the gases-brine phase equilibrium calculations. PRSI-CGCS does not incorporate energy conservation equations, and salt precipitation or dissolution is also not considered. Numerical experiments show that our simulator is scalable, robust and validated to simulate large-scale CO2 storage problems with hundreds of millions of grid blocks on a parallel supercomputer cluster. Besides, after our modification on scaling factors, the SAB method can reduce the number of stability analyses by 61.39 % to 88.71 %, thereby reducing simulation time. Furthermore, case studies indicate that injecting O2 and H2 along with CO2 reduces the stability or capacity of CO2 storage and increases the pressure required for injection. However, this impact is not significant when the impurity content is less than 10 %.

Site characterization of the Endurance CO 2 store, Southern North Sea, UK

The Endurance saline aquifer CO 2 store in the UK North Sea is the planned storage site for CO 2 emissions that will be captured from the East Coast Cluster. The site has been characterized to assess its suitability for injectivity, containment and capacity. The injection target is the Early Triassic Bunter Sandstone Formation, consisting of fine-grained sandstones deposited in fluvial, lacustrine and playa lake environments that were subject to repeated aeolian and fluvial reworking. The sandstones have excellent reservoir quality and are likely to be well connected due to the lack of preserved heterolithic layers. The trap is a large, four-way dip-closed anticline, sealed by mudstones and evaporites of the Middle Triassic Dowsing Formation. The top seal sediments are laterally extensive and geomechanically strong, and faulting observed in the overburden does not appear to connect to the reservoir, providing confidence that CO 2 containment will be secure. The risk of leakage through existing legacy wells is assessed as low. The maximum effective CO 2 storage capacity is c . 450 Mt: Phase 1 development of 100 Mt is equivalent to a storage efficiency factor of 3%, which is achievable without the need for brine production. First injection is planned from 2027.

Impact of Pressure-Dependent Interfacial Tension and Contact Angle on Capillary Heterogeneity Trapping of CO2 in Storage Aquifers

Summary Carbon dioxide (CO2) capillary trapping increases the total amount of CO2 that can be effectively immobilized in storage aquifers. This trapping, manifesting itself as accumulated CO2 columns at a continuum scale, is because of capillary threshold effects that occur below low-permeability barriers. Considering that capillary pressure is dictated by heterogeneous pore throat size, the trapped CO2 column height and associated CO2 saturation will vary spatially within a storage aquifer. This variation will be influenced by two pressure-dependent interfacial parameters—CO2/brine interfacial tension (IFT) and CO2/brine/rock contact angle. Our objective is to understand how the pressure dependence of these two parameters affects the heterogeneity of capillary trapped CO2 at a continuum scale. Our conceptual model is a 1D two-zone system with the upper zone being a flow barrier (low permeability) and the lower zone being a flow path (high permeability). The inputs to this model include microfacies-dependent capillary pressure vs. saturation curves and permeability values. The input capillary pressure curves were collected in the literature that represents carbonate microfacies (e.g., dolograinstone) in a prevalent formation in the Permian Basin. We then used the Leverett j-function to scale the capillary pressure curve for the two zones that are assigned with the same or different microfacies. During scaling, we considered the influence of pressure on both the IFT and contact angle of CO2/brine/dolomite systems. We varied the zone permeability contrast ratio from 2 to 50. We then assumed capillary gravity equilibriums and calculated the CO2 saturation buildup corresponding to various trapped CO2 column heights. The CO2 saturation buildup is defined as the CO2 saturation in the lower layer minus that in the upper one. We found that the saturation buildup can be doubled when varying pressure in a storage aquifer, after considering pressure-dependent IFT and contact angles. Thus, assuming these two parameters to be constant across such aquifers would cause large errors in the quantification of capillary trapping of CO2. The whole study demonstrates the importance of considering pressure-dependent interfacial properties in predicting the vertical distribution of capillary trapped CO2. It has important implications in developing a better understanding of leakage risks and consequent storage safety.

Relative permeability evolution with thermo-poromechanical process during N2 and scCO2 injection in brine saturated Deadwood sandstone from Aquistore

This study delves into the intrinsic and multiphase flow properties, specifically steady-state drainage relative permeability, of a subsurface Deadwood sandstone from the Aquistore CO2 storage site in Canada. Consecutive core-flooding experiments were conducted utilizing N2- and scCO2-brine pairs across a broad range of temperatures (20–70 °C) and isotropic effective stress (0–30 MPa). Moreover, we monitored crack initiation and propagation of the sandstone during uniaxial loading at an elevated temperature using an integrated approach that combines microCT scanning with an in-situ heating/loading test. Our findings reveal a 54 % decrease and a 3 % increase in the absolute permeability of the sandstone through isothermal compaction followed by thermal expansion processes, respectively. Elevating the temperature from 20 °C to 70 °C results in a systematic 24 % increase in irreducible brine saturation and nearly doubles the end-point N2 mobility, indicating an increased tendency of the rock surface towards the brine phase with temperature. Substituting N2 with scCO2 demonstrates a leftward shift in relative permeability and a decrease in irreducible brine saturation (from 0.36 to 0.31), consistent with low interfacial tension and the de-wetting effect during cyclic scCO2-brine injections. Micro-CT image analysis reveals micro-crack initiation at 10 MPa stress and 70 °C temperature, suggesting that a mixed impact of induced cracks, dynamic wettability, and thermo-mechanical deformation is responsible for the substantial increase in well injectivity over time in Aquistore. This novel experimental program provides indispensable insight into thermo-poromechanical and wettability controls on multiphase flow at the Aquistore injection site in Canada, with potential applicability to similar scenarios globally.

Tectonic, Geological and Hydrogeological Risks of CO2 Placement in Aquifers in the South of Sakhalin Island

The tectonic, geological and hydrogeological features of the south of Sakhalin Island have been considered in connection with the assessment of the possibility of placing CO2 in aquifers. It has been found that at the regional and zonal level of criteria, this territory can be classified as unpromising one. It has been concluded that implementation of landfill projects for the placement of CO2 in aquifers will face great geological risks for the drinking water supply to the population, and can also lead to serious environmental consequences for nature, including a shift in the balance in the aquatic ecosystem of Aniva Bay.

Uncertainty Quantification in CO2 Trapping Mechanisms: A Case Study of PUNQ-S3 Reservoir Model Using Representative Geological Realizations and Unsupervised Machine Learning

Evaluating uncertainty in CO2 injection projections often requires numerous high-resolution geological realizations (GRs) which, although effective, are computationally demanding. This study proposes the use of representative geological realizations (RGRs) as an efficient approach to capture the uncertainty range of the full set while reducing computational costs. A predetermined number of RGRs is selected using an integrated unsupervised machine learning (UML) framework, which includes Euclidean distance measurement, multidimensional scaling (MDS), and a deterministic K-means (DK-means) clustering algorithm. In the context of the intricate 3D aquifer CO2 storage model, PUNQ-S3, these algorithms are utilized. The UML methodology selects five RGRs from a pool of 25 possibilities (20% of the total), taking into account the reservoir quality index (RQI) as a static parameter of the reservoir. To determine the credibility of these RGRs, their simulation results are scrutinized through the application of the Kolmogorov–Smirnov (KS) test, which analyzes the distribution of the output. In this assessment, 40 CO2 injection wells cover the entire reservoir alongside the full set. The end-point simulation results indicate that the CO2 structural, residual, and solubility trapping within the RGRs and full set follow the same distribution. Simulating five RGRs alongside the full set of 25 GRs over 200 years, involving 10 years of CO2 injection, reveals consistently similar trapping distribution patterns, with an average value of Dmax of 0.21 remaining lower than Dcritical (0.66). Using this methodology, computational expenses related to scenario testing and development planning for CO2 storage reservoirs in the presence of geological uncertainties can be substantially reduced.

Suitability of basins in Russia for aquifer CO2 storage: evaluation strategy

Suitability of basins in Russia for aquifer CO2 storage: evaluation strategy

A novel deep learning-based automatic search workflow for CO2 sequestration surrogate flow models

Numerical simulation can significantly enhance subsurface resource utilisation's efficiency and economic benefits by multiphase flow in heterogeneous porous media. However, numerical simulation brings enormous computational demands and time consumption due to high-dimensional nonlinearity, heterogeneity, and coupling of multiple physical processes. Surrogate models can accelerate the establishment of complex models without sacrificing accuracy. However, creating well-performing surrogate models requires extensive human intervention and trial-and-error processes, even for cross-domain experts. This study proposes an automated surrogate flow model workflow based on deep learning called Surrogate Flow Model Search (SFMS). By incorporating neural architectures and loss functions into joint hyperparameter optimisation, SFMS automates many complex and time-consuming tasks involved in model development, such as designing neural architectures and loss functions. The automated surrogate model construction workflow enables researchers to develop high-quality surrogate models without extensive deep-learning expertise. We demonstrate the effectiveness of SFMS using saline aquifer CO2 injection as an example. The results show that SFMS can automatically generate a highly accurate surrogate flow model in a short time (<1300 s), capable of accurately predicting 120-time steps under different well controls and placements with a low average relative error (<0.4%). Therefore, SFMS can significantly reduce the time and effort required to develop accurate and reliable surrogate models, providing a new approach to building surrogate models.

Inorganic Hydrogeochemistry in the 21st Century.

Chemical and isotopic processes occur in every segment of the hydrological cycle. Hydrogeochemistry-the subdiscipline that studies these processes-has seen a transformation from "witch's brew" to credible science since 2000. Going forward, hydrogeochemical research and applications are critical to meeting urgent societal needs of climate change mitigation and clean energy, such as (1) removing CO2 from the atmosphere and storing gigatons of CO2 in soils and aquifers to achieve net-zero emissions, (2) securing critical minerals in support of the transition from fossil fuels to renewable energies, and (3) protecting water resources by adapting to a warming climate. In the last two decades, we have seen extensive activity and progress in four research areas of hydrogeochemistry related to water-rock interactions: arsenic contamination of groundwater; the use of isotopic and chemical tracers to quantify groundwater recharge and submarine groundwater discharge; the kinetics of chemical reactions and the mineral-water interface's control of contaminant fate and transport; and the transformation of geochemical modeling from an expert-only exercise to a widely accessible tool. In the future, embracing technological advances in machine learning, cyberinfrastructure, and isotope analytical tools will allow breakthrough research and expand the role of hydrogeochemistry in meeting society's needs for climate change mitigation and the transition from fossil fuels to renewable energies.

Optimization of distribution networks for water and energy in isolated regions: A multi-objective approach incorporating ocean thermal energy conversion technologies

The limited resources and increased vulnerability to climate change and environmental degradation in isolated regions such as islands and archipelagos make the development of sustainable technologies for water and energy provision a crucial factor in addressing resource scarcity and mitigating anthropogenic impact. This work presents a multi-objective optimization analysis incorporating an Open Cycle Ocean Thermal Energy Conversion (OC-OTEC) plant in the water and energy distribution networks of an isolated region. The optimization considers three interrelated objectives: economic viability measured by annual profit, environmental sustainability reflected in reduced CO2 emissions and aquifer water usage, and social impact through job creation. The optimization results demonstrate the positive impact of integrating the OC-OTEC plant into the Tahiti distribution network, achieving an optimal configuration that balances economic, environmental, and social considerations. Finally, the proposed model is applied to Tahiti of French Polynesia as a case study.

Study Makes Value Proposition for Carbon-Neutral Fuel From Light Tight Oil

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 2021-5437, “Carbon-Neutral Fuel From Light Tight Oil: A Value Proposition,” by Christine A. Ehlig-Economides, SPE, University of Houston. The paper has not been peer reviewed. _ Emissions for light tight oil often begin with associated gas. Rather than flare the stranded methane, an option may be to use it to power capture of CO2 from the air using direct air capture (DAC) technologies. This study catalogs global gas/oil ratio (GOR) data to identify currently produced light crude oils that could be rendered carbon-neutral through the DAC mechanism. It then considers operational aspects, including proximity to a suitable location for a DAC unit and proximity to subsurface utilization or storage opportunities, that favor or discourage this approach. Introduction Previous work by the author defined carbon-neutral crude oil (CNCO) as crude oil that has offset the CO2 to be emitted by its combustible products before its arrival at the sale point. Other authors refer to enhanced oil recovery (EOR) using anthropogenic CO2 and including monitoring, verification, and reporting as EOR+. They describe three EOR+ categories: conventional, advanced, and maximum storage. Conventional storage minimizes CO2 use to reduce cost, resulting in net usage of 0.3 t CO2/bbl. Advanced-storage miscible flooding follows current best practices for optimized oil recovery and also may involve some “second-generation” approaches that boost CO2 use, resulting in net usage of 0.6 t CO2/bbl. Maximized storage effectively uses the reservoir pore space for additional CO2 storage without additional oil production and may include removing water, resulting in net usage of 0.9 t CO2/bbl. CO2 Capacity The pore-space requirements for saline aquifer CO2 storage depend on whether primary or secondary storage is envisioned for the short term. Primary storage entails bulk CO2 injection into an aquifer storage volume effectively limited by interference with neighboring injection wells, while secondary storage entails producing the same volume from the reservoir as is injected as CO2. The bulk rock volume required to store CO2 dissolved in brine is approximately 200 times the original coal volume (Fig. 1). Limiting the injection pressure below the fracturing pressure to avoid breaching the caprock, however, further limits the CO2 storage capacity to approximately 6% of the pore space. This makes the multiplier nearly 120 times the original coal volume without CO2 dissolution. Generally, CO2 captured from stationary point sources and stored through multiwell bulk injection in a saline aquifer has a primary storage capacity of approximately 4.2 t CO2/acre-ft without increasing the original aquifer pressure. Three tables in the complete paper list inputs for these estimations and parameters derived from these inputs for cases corresponding to primary and secondary storage without aquifer pressurization. If CO2 injection elevates the aquifer average pressure, this increases the risk of inducing earthquakes and fracturing through the caprock. Using a typical fracture gradient of 0.7 psi/ft, injectivity of 3.23 BOPD/ft/psi could enable elevating the aquifer average pressure to 6,297 psia, which would, in turn, enable increasing the primary storage capacity to 18 t CO2/acre-ft and secondary storage capacity to 135 t CO2/acre-ft, again without CO2 dissolution. It is useful to compare maximized EOR+ with secondary CO2 storage in a saline aquifer. Effectively, maximized storage is like secondary saline aquifer storage in a sealed and trapped reservoir volume. Elevating pressure can increase the storage efficiency in either case, though with associated risks.

Analysis of CO2 Migration in Horizontal Saline Aquifers during Carbon Capture and Storage Process

The storage of CO2 has become an important worldwide problem, considering that an excess of CO2 in the Earth’s atmosphere causes dramatic changes in its climate. One possible solution is to remove the excess of CO2 from the atmosphere, capture it in the process of creation, and store it safely, negating the possibility of its return into the atmosphere. This is the process of Carbon Capture and Storage (CCS). In the following paper, the authors investigate horizontal saline aquifers and their ability to store CO2. The authors’ application of sensitivity analysis on horizontal migrations uncovered that CO2 permeability and aquifer porosity have a considerable impact on horizontal migrations. During the migration process, CO2 can reach tens of kilometers from its injection point. By introducing effective CO2 density to the conduction velocity term, the authors showcase that the convection-diffusion equation for compressible fluids can be replaced with the equation for incompressible fluids. The buoyancy factor in convective velocity is as density dependent as in conduction velocity. By means of introducing an effective density to the aforementioned term, the process of transport via variable convective velocity can be substituted for a process which is effective, constant, and not density dependent.

Pressure-derived storage efficiency for open saline aquifer CO 2 storage

Various approaches are used at the preliminary stage (before flow modelling studies) to evaluate the resources of saline aquifers for storing CO 2 . The two approaches used most commonly are the volumetric ‘open aquifer’ and ‘closed aquifer’ approaches, which provide the end members for the resources of a given aquifer store. We propose a novel approach based on extending the analytical aquifer methods, which have been routinely used for decades in the oil and gas industry, to CO 2 saline aquifer storage. The CO 2 storage resource is derived from the pore volume liberated by pressurization to accommodate CO 2 in the store, which is the sum of: (i) the volume of the store obtained by compression; and (ii) the volume of water outflow towards the regional aquifer. It enables the CO 2 storage resources and storage efficiencies for pressure-limited stores (meaning when the resource is not even more limited by CO 2 migration issues) to be estimated. Formalism is presented, as well as implications and limitations of the method. With this method, storage efficiencies are directly connected to closed store efficiencies that are corrected for the water outflux and pressure dissipation from the CO 2 store into the regional aquifer, reconciling the ‘closed’ and ‘open’ approaches. We present an application to the Havnsø saline aquifer structure in order to highlight the consequences of the CO 2 storage resource evaluation and also of appraisal and development phases.

Buoyant Flow of H2 Vs. CO2 in Storage Aquifers: Implications to Geological Screening

Summary Hydrogen will play an important role in the quest to decarbonize the world’s economy by substituting fossil fuels. In addition to the development of hydrogen generation technologies, the energy industry will need to increase hydrogen storage capacity to facilitate the development of a robust hydrogen economy. The required hydrogen storage capacity will be much larger than current hydrogen and natural gas storage capacities. There are several geological storage options for hydrogen that include depleted hydrocarbon fields and aquifers, where more research is needed until the feasibility of storing hydrogen at scale is proved. Here, we investigate the buoyant flow of H2 (as a working gas) vs. CO2 (as a cushion gas) separately in a representative storage aquifer. Buoyant flow can affect the maximum storage, capillary trapping, likelihood of leakage, and deliverability of aquifer-stored hydrogen. After building a 2D geological reservoir model initially filled with saline water, we ran numerical simulations to determine how hydrogen placed at the bottom of an aquifer might rise through the water column. The Leverett j-function is used to generate heterogeneous capillary entry pressure fields that correlate with porosity and permeability fields. Hydrogen viscosities were based on the Jossi et al. correlation, and the density was modeled using the Peng-Robinson equation of state. We then simulated several scenarios to assess flow during short- (annually) and long- (several years) term storage. For comparison purposes, we also ran CO2 storage simulations using the same geological model but with CO2-brine-rock properties collected from the literature. For a representative storage aquifer (323 K, 15.7 MPa, and mean permeability of 200 md), significant fingering occurred as the hydrogen rose through the saline water column. The hydrogen experienced more buoyant flow and created flow paths with increased fingering when compared with CO2. Individual hydrogen fingers are thinner than the CO2 fingers in the simulations, and the tips of hydrogen finger fronts propagated upward roughly twice as fast as the CO2 front for a typical set of heterogeneity indicators (Dykstra-Parson’s coefficient Vdp = 0.80, and dimensionless autocorrelation length λDx = 2). The implications of buoyant flow for hydrogen in saline aquifers include an increased threat of leakage, more residual trapping of hydrogen, and, therefore, the need to focus more on the heterogeneity and lateral correlation behavior of the repository. If hydrogen penetrates the caprock of an aquifer, it will leak faster than CO2 and generate more vertical flow pathways. We identify possible depositional environments for clastic aquifers that would offer suitable characteristics for storage.

CO2 storage potential assessment of offshore saline aquifers in China

Saline Aquifer CO2 Storage (SACS) has become a vitally important technology for mitigating climate change brought on by anthropogenic and fossil fuel emissions. Application of SACS projects in offshore saline aquifers in China is quite promising, and the CO2 storage technical and economic potential are considerable. However, the storage capacities achieved from different analytical and numerical methods varies a lot from each other since the main factors taken into account are variable.In this paper, different methodologies are applied to conduct the assessment of CO2 storage capacity of offshore saline aquifers including Bohai Bay Basin in northern China, also Beibu Gulf Basin and Yinggehai Basin in southern China. Results show that the storage capacity obtained from European Commission’s method is much less than that determined by the other three methods (i.e., USDOE, CSLF and CO2BLOCK method) since it mainly effected by the area of the saline aquifers. Since both of the CSLF and CO2BLOCK methods take into the account the storage mechanisms such as geological structure storage, residual gas storage and dissolution storage, the results seem more reasonable. In addition, the CO2BLOCK method considers the formation stability during injection as well, which is more in accordance with the reality. In summary, the CO2 storage potential of Bohai Bay Basin, Beibu Gulf Basin, and Yinggehai Basin are 39.98, 53.22, and 13.37 Gt, respectively. This further verifies the great potential of industrial-scale pilot and demonstration CO2 storage projects in offshore deep saline aquifers in China.

Trace metals in CO 2 -rich Green River springs, Utah, USA: an analogue for engineered storage

Abstract Sedimentary rocks with high natural CO 2 concentrations provide invaluable analogues for the long-term engineered storage of CO 2 . Some previous studies have reported high trace metal concentrations in sandstone aquifers exposed to CO 2 , a cause for concern should stored CO 2 leak into underground sources of drinking water. However, the intensively studied Jurassic sandstone aquifer in the San Rafael–Green River (Utah, USA) area has trace metal concentrations that are within US Environmental Protection Agency's limits for drinking water. Exceptions are As which is plausibly introduced into the aquifer by saline brines external to the aquifer, and salinity which largely is. This shows that CO 2 in aquifers does not inevitably cause trace metal contamination. CO 2 –water–rock batch experiments elucidated the controls on the trace metal concentrations. After the addition of CO 2 , the experiments reproduce Cu, Cd, Hg, Ni and Zn well, with less good agreement for Cr and Pb although these are still low compared to drinking water standards. Major cations used as fingerprints for mobilization mechanisms suggest that the trace metals are largely derived by desorption, possibly from grain-coating Fe-oxides, rather than by the dissolution of mineral phases. Possible exceptions are Pb and Ni, plus As which is derived from saline brines.

Study on influence factors of saline aquifer CO2 sequestration under the constraint of cap rock

In view of the practical problems faced by the CO2 sequestration in aquifers, this paper considers the influence of injection rate, water production rate, and other factors on CO2 injection amount, residual sequestration amount, dissolution sequestration amount, and pressure evolution under the constraint of cap rock breakthrough pressure is studied by using a numerical simulation method, and the sequestration potential is evaluated. The results show that: (1) Water production measures can improve CO2 injection, dissolution sequestration, and residual sequestration. (2) Low ratio of vertical permeability to horizontal permeability is conducive to the security and stability of CO2 sequestration in the long term. The research content provides support for the evaluation of CO2 saline aquifer sequestration potential and field practice.

Sources and concentrations of methane, ethane, and CO2 in deep aquifers of the Surat Basin, Great Artesian Basin

Understanding the occurrence and sources of methane in aquifers is an international issue, especially in regions that host oil and gas reservoirs. Multi-isotopic studies are important to understand sources and concentrations of dissolved gases in aquifers of basins that host oil and gas extraction; or future CO2, natural gas, hydrogen storage, or compressed air energy storage. The largest artesian basin in the world, the Great Artesian Basin, extends across more than one fifth of Australia providing a fresh water source from various aquifers. The Precipice and Hutton sandstones, aquifers of the Surat Basin in the eastern Great Artesian Basin, are important water resources for town water supply, agriculture, mines, feedlots, and private landholders in Queensland. Overlying and underlying formations host gas extraction. The southern part of the basin in Queensland additionally hosts an oil field, and potential CO2 storage sites, therefore understanding the aquifer gas concentrations, processes and sources is important for fluid management. The dissolved concentrations of methane and ethane in the Hutton Sandstone were up to 96 mg/L and 1 mg/L respectively, and in the Precipice Sandstone methane ranged up to 2100 mg/L and ethane 6.5 mg/L in the southern Surat Basin. Dissolved gas concentrations were measured by an open and closed sampling method, with the concentrations lower from open sampling, and the gas wetness parameter systematically slightly lower. The Hutton Sandstone aquifer dissolved gas isotopic signatures are mainly consistent with primary microbial CO2 reduction generating methane in situ, with fractionation factors indicating acetate fermentation in a few cases. The Hutton Sandstone δ13C-DIC, δ13C-CO2, and δ13C-CH4 have an enrichment trend with increasing depth that indicate a microbial substrate depletion effect. Moonie Oil Field Precipice Sandstone and Evergreen Formation samples plot in the thermogenic region, with enriched δ13C-CO2 indicating microbial biodegradation is also occurring. The Precipice Sandstone aquifer samples have a mixed microbial CO2 reduction and early mature thermogenic gas signature in both isotope cross plots and gas wetness diagrams, with a subset of sampled δ13C-C2H6 and isotope factors consistent with early mature thermogenic gas. A potential historic source of thermogenic gas is the underlying gas reservoir of the Bowen Basin. Large volumes of water are abstracted from these aquifers, hence dissolved gases may contribute to greenhouse gas emissions.

Tracing CO2 leakage and migration using the hydrogeochemical tracers during a controlled CO2 release field test

A critical environmental issue in carbon capture and storage (CCS) is potential CO2 leakage, which accompanies geochemical reactions with aquifer materials. To investigate the hydrogeochemical effects of CO2 leakage on shallow groundwater at the early stage of CO2 leakage and to evaluate a hydrochemical or isotopic tracer for CO2 migration, a controlled CO2 release experiment was performed in a siliciclastic aquifer at the Environmental Impact Evaluation Test (EIT) site, South Korea. After the baseline survey of hydrochemical and carbon isotope (δ13CDIC) compositions, CO2-infused water was injected at a rate of 5.5 m3/day for 26 days at ∼22 m below ground level in the ∼40 m thick heterogeneous aquifer whose pressure gradient was increased to approximately 10 times the natural gradient to make a flow path along monitoring wells. The arrival of CO2 plume was determined at each monitoring well by the decrease in pH and the increase in the partial pressure of CO2 (PCO2) and EC. δ13CDIC decreased at the arrival of CO2 plume and showed high correlations with log PCO2 since the δ13CDIC of injected CO2 (−24.7‰) was distinct from that of ambient groundwater (−16.7‰) and little carbon sources existed in the aquifer. The spatial and temporal evolution of hydrochemical and isotopic compositions observed using a monitoring well network indicated that the CO2 plume migrated along a preferential pathway overwhelming induced pressure gradient due to water table mounding at injection and that the plume sank to some degree probably due to its large density. Concentrations of hydrochemical elements displayed three types of behavior: (1) pulse-like with rapid increases at the arrival of CO2 plume and decreases despite the continuous injection of CO2 similar to EC (HCO3, Ca, Mg, Na, K, Sr, and Ba), (2) pH dependent with relatively slow increases and decreases in concentrations (SiO2 and Mn), and (3) rapid increases but slow decreases (Li). The hydrochemical variations indicated the dissolution of a limited amount of reactive minerals such as calcite, followed by cation exchange at the early stage of CO2 leakage in siliciclastic aquifers. Based on the study result, Li was an effective hydrogeochemical tracer to monitor the migration of CO2 in siliciclastic aquifers as well as pH, EC, and δ13CDIC.