Aquifer Storage Research Articles

Brine Salinity: A Deciding Factor for Carbondioxide Dissolution and Trapping during Geological Sequestration

Adequate geological storage of carbondioxide in saline aquifers is a function of several factors that requires understanding and examination. Previous works have argue that solubility of carbondioxide in brine decreases as the salinity of the brine increases, but it is unclear in the literature the impact of salinity on carbondioxide (CO2) trapping during sequestration. This work adopt a simulation based approach to determine CO2 dissolution and trapping at different salinities. A dataset was written and validated with CMG’s greenhouse gases simulator and the thermodynamics properties calculation carried out with Peng-Robinson equation of state. Four sensitivity analyses was conducted with brines of no salinity (pure water), salinity of 100000ppm, 200000ppm and 300000ppm and model outputs compared for CO2 sequestration. The result shows that CO2 solubilised in water with zero level salinity, and a lower gas cap size was formed at the top of the structure. Later, gas cap size increases as the salinity level increases at the top of the structure. Also, the moles soluble in water decreases as the salinity level increases with the least moles for zero water salinity. Alternatively to the moles solubilised, the number of moles of CO2 trapped increases with the salinity level. CO2 storage in deep saline aquifers is the best storage techniques but its injection into aquifer of high salinity reduced its solubility.

A high-efficient method to upscale H2 migration within heterogeneous saline aquifers

Drawing upon a range of energy storage methods that cover daily, weekly, and seasonal dynamics presents a route to reduce carbon dioxide emissions per unit of energy delivered. The utilization of renewable energy to generate, store, and recycle hydrogen stands out as a particularly promising strategy to address the seasonal fluctuations in energy production and usage. Deep saline aquifers offer a feasible solution for large-scale hydrogen storage, tailored to meet the demands of long-term storage requirements. This research introduces an upscaling method based on percolation theory, aiming to reduce computational costs in simulating H2 migration across diverse saline aquifers with different correlation lengths. Two geological models of distinct correlation lengths showcase the method's effectiveness. In the model with a 1.2-m correlation length, percolation-based upscaling yields final H2 saturation errors of 8.76 % in the main area and 3.7 % in the sink area, reducing runtime nearly sevenfold. Similarly, the model with a 4.0-m correlation length demonstrates final H2 saturation errors of 10.7 % in the main area and 1.27 % in the sink area, decreasing runtime almost fivefold. To bolster the credibility of the proposed upscaling method, parameters derived from the Brooks-Corey and van Genuchten models are calibrated to align with experimentally acquired H2-water multiphase flow properties. The resulting coarse-scale model accurately replicates primary permeability and H2 migration behavior, maintaining errors below 5 %. Importantly, dominant H2 migration mechanisms during underground hydrogen storage in saline aquifers are preserved in upscaled models, enabling efficient H2 saturation predictions beneath caprock. This study enhances our understanding of fine-scale H2 migration in complex geological systems and sheds light on integrating small-scale capillary barrier characteristics during upscaling.

Geochemical impact of biomethane and natural gas blend injection in deep aquifer storage

Biomethane is one of the main renewable gases available today to offset fossil gas and decarbonize the energy system. The EU is seeking to rapidly replace part of the natural gas usually stored in deep saline aquifers by biomethane which contains up to 10000 ppm of O2. This study presents for the first-time assessment of deep aquifers’ resilience to biomethane and natural gas blend injection into two sandstone reservoirs with different mineral paragenesis from the Paris Basin (France). Multiphase reactive transport modeling allowed to evaluate changes in gas and water quality, mineralogy and moreover, to identify major resilience properties of storage facilities necessary to buffer the oxygen reactivity and induced acidification coming from gas–water–rock interactions. In the presence of pyrite, the injected oxygen is consumed during pyrite oxidation and contributes to the acidification of the formation water close to the injection point. However, the injection of 1% mole fraction of CO2(g) contained in the gas blend is found to be the main acidification factor. The analysis of reservoir resilience showed three protection levels of pH buffering capacity, which can effectively mitigate an increase in oxygen content up to 1000 ppm: (i) calcite dissolution, (ii) plagioclase and clay dissolution and (iii) clay sorption capacity. Models predict that the gas blend injection could induce minimal but long-term change in the mineralogy without significantly impacting the global porosity. Overall, both sandstones can preserve the quality of the gas plume despite partial CO2(g) exsolution induced by the geochemical perturbation of the formations. The developed models will be used as a basis for assessment of renewable natural gas storage facilities in the long-term.

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.

Enhancing carbon sequestration: Innovative models for wettability dynamics in CO2-brine-mineral systems

This study investigates the application of machine learning techniques—specifically convolutional neural networks, multilayer perceptrons and cascaded forward neural networks —to understand the wettability of the CO2/brine/rock system, a critical factor in carbon dioxide (CO2) capture, utilization, and storage in deep saline aquifers. Understanding wettability is essential for improving the efficacy of CO2 storage. The study incorporates variables such as salinity, mineral types, measurement methods, pressure, and temperature into the machine learning models. Using a dataset of 876 samples from existing literature, the proposed models were trained and optimized using the Adam optimizer, Levenberg-Marquardt algorithm, and particle swarm optimization respectively.The performance of these models was evaluated through plot analysis, statistical indicators, and the Taylor diagram, demonstrating a high level of accuracy compared to experimental data. The specifically convolutional neural networks model showed exceptional accuracy in predicting CO2 wettability in brine, with a root mean square error of 0.9612 and coefficient of determination value of 0.9982. The minimal presence of outliers in the specifically convolutional neural networks model further confirms its robustness.This research highlights the effectiveness of deep learning in modeling complex wettability behaviors in CO2-brine-mineral systems, offering substantial insights for enhancing carbon dioxide (CO2) capture, utilization, and storage strategies. The novelty of this work lies in its comprehensive integration of multiple variables and the use of advanced machine learning optimization techniques, going beyond previous efforts by achieving higher predictive accuracy and providing a more detailed understanding of wettability dynamics.

Multi-Facet analysis of analytical and numerical models to resolve sustainable artificial recharge rates in unconfined aquifers

Managed aquifer recharge (MAR) has emerged as a potential solution to resolve water insecurity, globally. However, integrated studies quantifying the surplus source water, suitable recharge sites and safe recharge capacity is limited. In this study, a novel methodology is presented to quantify transient injection rates in unconfined aquifers and generate MAR suitability maps based on estimated surplus water and permissible aquifer recharge capacity (PARC). Subbasin scale monthly surplus surface runoff was estimated at 75% dependability using a SWAT model. A linear regression model based on numerical solution was used to capture the aquifer response to injection and to calculate PARC values at subbasin level. The available surplus runoff and PARC values was then used to determine the suitable site and recharge rate during MAR operation. The developed methodology was applied in the semi-arid region of Lower Betwa River Basin (LBRB), India. The estimated surplus runoff was generally confined to the monsoon months of June to September and exhibited spatial heterogeneity with an average runoff rate of 5000 m3/d in 85% of the LBRB. Analysis of the PARC results revealed that thick alluvial aquifers had large permissible storage capacity and about 50% of the LBRB was capable of storing over 3500 m3/d of water. This study revealed that sufficient surplus runoff was generated in the LBRB, but it lacked the adequate safe aquifer storage capacity to conserve it. A total 65 subbasins was identified as the best suited sites for MAR which had enough surplus water and storage capacity to suffice 20% of the total water demand in the LBRB. The developed methodology was computationally efficient, could augment the field problem of determining scheduled recharge rates and could be used as a decision-making tool in artificial recharge projects.

Extended Aquifer System Pressure Behavior under Carbon Storage

Summary Most reported carbon storage projects have involved inexpensive carbon dioxide (CO2) capture from gas processing plants or ethanol refineries. However, widespread carbon capture and storage (CCS) application must avoid any risk that high capital investment cost for carbon capture from stationary point sources leads to unanticipated issues related to the aquifer storage. This paper reviews successful and unsuccessful carbon storage projects and explains simple extended aquifer system fundamentals that must be considered in selecting a storage aquifer. This study begins by evaluating reported carbon storage projects in the context of an extended aquifer system with specific attention to initial formation pore pressure and potential or known hydraulic vertical or lateral communication with hydrocarbon accumulations and/or fresh water. Further study focuses on how the contrast between injection well and aquifer pressure evolution enables understanding of the overall aquifer material balance. Finally, we consider implications of brine migration during and after long-term CO2 injection in unconfined aquifers. Experience in the petroleum industry with aquifer behavior includes presence or lack of water influx and production from hydrocarbon reservoirs that share a common aquifer. Of particular importance is the observation that hydrostatic initial formation pressure indicates the possibility that a petroleum system, or an extended aquifer system without hydrocarbon accumulation(s), connects to atmospheric pressure through an unconfined aquifer. In such cases, indefinite injection will never increase the regional aquifer pressure. Furthermore, initial formation pressure that exceeds hydrostatic pressure implies a petroleum system or an extended aquifer system that is volumetrically limited. In such cases, injection will increase the system pressure, and pressure monitoring can detect leakage from the system. Finally, CO2 injection into an aquifer will displace brine in the direction of lower pressure that could relate to distant production from the same aquifer or from hydrocarbon reservoirs with which it communicates. Reasons for known carbon storage project interruptions have included unexpected lateral plume migration or aquifer pressure increase during CO2 injection that might have been anticipated with attention to straightforward consideration of aquifer-enabled hydraulic communication. Such extended aquifer dynamics must be included in long-term models for permanent CO2 storage during and after injection.

Carbon Dioxide Capture and Storage (CCS) in Saline Aquifers versus Depleted Gas Fields

Saline aquifers have been used for CO2 storage as a dedicated greenhouse gas mitigation strategy since 1996. Depleted gas fields are now being planned for large-scale CCS projects. Although basalt host reservoirs are also going to be used, saline aquifers and depleted gas fields will make up most of the global geological repositories for CO2. At present, depleted gas fields and saline aquifers seem to be treated as if they are a single entity, but they have distinct differences that are examined here. Depleted gas fields have far more pre-existing information about the reservoir, top-seal caprock, internal architecture of the site, and about fluid flow properties than saline aquifers due to the long history of hydrocarbon project development and fluid production. The fluid pressure evolution paths for saline aquifers and depleted gas fields are distinctly different because, unlike saline aquifers, depleted gas fields are likely to be below hydrostatic pressure before CO2 injection commences. Depressurised depleted gas fields may require an initial injection of gas-phase CO2 instead of dense-phase CO2 typical of saline aquifers, but the greater pressure difference may allow higher initial injection rates in depleted gas fields than saline aquifers. Depressurised depleted gas fields may lead to CO2-injection-related stress paths that are distinct from saline aquifers depending on the geomechanical properties of the reservoir. CO2 trapping in saline aquifers will be dominated by buoyancy processes with residual CO2 and dissolved CO2 developing over time whereas depleted gas fields will be dominated by a sinking body of CO2 that forms a cushion below the remaining methane. Saline aquifers tend to have a relatively limited ability to fill pores with CO2 (i.e., low storage efficiency factors between 2 and 20%) as the injected CO2 is controlled by buoyancy and viscosity differences with the saline brine. In contrast, depleted gas fields may have storage efficiency factors up to 80% as the reservoir will contain sub-hydrostatic pressure methane that is easy to displace. Saline aquifers have a greater risk of halite-scale and minor dissolution of reservoir minerals than depleted gas fields as the former contain vastly more of the aqueous medium needed for such processes compared to the latter. Depleted gas fields have some different leakage risks than saline aquifers mostly related to the different fluid pressure histories, depressurisation-related alteration of geomechanical properties, and the greater number of wells typical of depleted gas fields than saline aquifers. Depleted gas fields and saline aquifers also have some different monitoring opportunities. The high-density, electrically conductive brine replaced by CO2 in saline aquifers permits seismic and resistivity imaging, but these forms of imaging are less feasible in depleted gas fields. Monitoring boreholes are less likely to be used in saline aquifers than depleted gas fields as the latter typically have numerous pre-existing exploration and production well penetrations. The significance of this analysis is that saline aquifers and depleted gas fields must be treated differently although the ultimate objective is the same: to permanently store CO2 to mitigate greenhouse gas emissions and minimise global heating.

Delineation of aquifer storage potential in response to regional groundwater development

Developing aquifers as part of sustainability efforts toward groundwater development is a tactical approach to meeting water demand and management objectives. Delineation of aquifer storage potential (ASP) and longitudinal conductance (SL\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$${S}_{L}$$\\end{document}) is a good approach to protect and manage groundwater resources. A Schlumberger configuration was applied to delineate fifteen (15) vertical electrical sounding (VES) stations alongside a 2D electrical resistivity imagery (ERI) profile and regional borehole data to characterize the regional ASP. The results of the study show that the layer resistivity and thickness values of the regional aquifer unit range from 39.9–105 Ωm and 15–44 m, respectively, while the overburden thickness overlays the regional aquifer unit varied between 5–10 m corresponding to the regional borehole data. The weathered/fractured basemen, which constitute the regional aquifer unit were delineated, which consists of shallow, moderate, and deep aquifer zones. The deep aquifer zones fall within the depth of 30–44 m and are considered suitable for groundwater prospective. The weathered layer with appreciably low resistivity values with thick aquifer regolith has also been identified as most suitable for borehole siting. The weathered/fractured encountered within thick aquifer regolith were mapped as the region with a high ASP for groundwater development. In addition, the values of longitudinal conductance, SL\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$${S}_{L}$$\\end{document} and transverse resistance, RT\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$${R}_{T}$$\\end{document} estimated from aquifer parameters vary between 0.21-0.85Ω-1\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$$0.21-0.85 \\,{\\Omega }^{-1}$$\\end{document} and 1695-3124Ωm2\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$$1695-3124\\, {\\Omega m}^{2}$$\\end{document}, respectively. The SL\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$${S}_{L}$$\\end{document} values show that the study area falls within moderate (0.20-0.69Ω-1\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$$0.20-0.69 \\,{\\Omega }^{-1}$$\\end{document}) and good (0.7-4.9Ω-1\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$$0.7-4.9 \\,{\\Omega }^{-1}$$\\end{document}), which invariably determined the regional aquifer protective capacity. Thus, the DC geoelectrical approach has been successfully employed in a lateritic-based environment to delineate aquifer-promising zones for regional groundwater development.

Technology readiness level assessment of carbon capture and storage technologies

The global energy sector has experienced significant expansion in recent years, driven by rising demand and technological advancements. This growth has led to both opportunities and challenges, including global warming and the need to offset global carbon emissions. A wide range of technological maturity characterizes the current state of carbon capture and storage (CCS) technologies. To efficiently navigate and accelerate the implementation of these solutions, conducting an in-depth assessment of various CCS technologies is necessary. In the literature, maturity assessment-based study of CCS technologies exists only using expert surveys. This study aimed to conduct a technology readiness level (TRL) assessment of CCS technologies with the help of a multi-faceted approach comprising a literature review, technology identification, data collection, TRL mapping, expert survey, and comparative analysis. To achieve this, 79 CCS projects from the literature were analyzed to identify growing trends in the CCS industry. The analysis shows that both pre-combustion and post-combustion capture are mature technologies achieving TRL 9, while oxy-fuel capture is ranked at TRL 7. Similarly, carbon storage technologies achieved high ranking, enhanced oil recovery (EOR) and storage in saline aquifers are fully commercial and ranked at TRL 9. Enhanced coal bed methane (ECBM) extraction is trailing at TRL 3 in the research phase. In addition, a total of 21 experts were surveyed, and their statements corroborate the conclusions of the literature review. The research concludes that post-combustion capture and EOR are the most popular CCS technologies, respectively.

Karst Aquifer Characterization by Means of Its Karstification Degree and Time Series Analysis (Case: Ngerong Spring in Rengel Karst, East Java, Indonesia)

The purpose of this study is to define the characteristics of the karst aquifer, which is approximated by the parameters of (1) degree of karstification (Dk) and (2) time series analysis (cross-correlation and auto-correlation). This research focuses on the Ngerong Spring, the largest spring in Rengel Karst, East Java, Indonesia. Pendant rain gauge RG-3M and HOBO U20L-02 water-level data loggers were installed over one year with a recording interval of 15 minutes. Furthermore, after one year of time-series discharge data was obtained, the discharge recession coefficient was applied to make the recession formula. It was then used to estimate the karstification degree scale from 1 to 10. The aquifer memory system and the spring response to rainfall events were analyzed by auto-correlation and cross-correlation. The results of this study indicate that the karstification degree (Dk) of the Ngerong Spring system is 4.8-5.0, with one laminar and one turbulent flow subregime type. The aquifer system comprises a subregime with turbulent and laminar flow, where the substantial role in groundwater discharge plays the subregime with laminar flow. Meanwhile, time series analysis shows that the capacity of aquifer storage in the Ngerong Spring is large enough. It has a memory effect for 26.41 days, followed by a rapid response to rainfall events within 8 hours. Compared with several other karst sites in Java, the Ngerong Spring aquifer has the youngest development level with the best storage and the slowest release.

Dynamics of hydrogen storage in subsurface saline aquifers: A computational and experimental pore-scale displacement study

The catastrophic effects of climate change can be mitigated by transitioning to renewable energy sources such as wind, solar, and hydropower while utilizing hydrogen (H2) as an energy carrier. As renewable fuel sources are intermittent and location-specific, large-scale, long-term storage options for H2 must be explored with high necessity. Subsurface hydrogen storage in saline aquifers provides a vital scope to store H2 gas in available pore voids with minimal environmental risk. In this work, a highly heterogeneous porous micromodel was used to study the immiscible two-phase dynamics at high-temperature, high-pressure saline aquifer conditions using computational fluid dynamics (CFD) simulation based on volume of fluid (VOF) method. A set of microfluidic experiments were carried out under atmospheric conditions to validate the numerical model. The VOF model was observed to show good agreement with microfluidic experiments. An unstable displacement pattern with viscous fingering was observed during various flow conditions that captured high pressure (15 and 25 MPa) and temperature conditions (323 and 343 K). It was observed that fingering displacement of brine limits the storage spaces for hydrogen, which consequently follows the high permeable path. As a result, only 0.272 fraction of brine was invaded by the H2 at a temperature of 323 K and pressure of 15 MPa. A comparison between H2-brine and nitrogen (N2)-brine flow dynamics revealed a 46% less storage capacity of porous media for H2. Formations bearing high temperature (343 K) showed an 11.27% increase in H2 storage capacity, while pressure increase had negligible effect. At low capillary number (Ca), more snap-off effects resulted in higher trapping of H2 gas. This study aims to provide meaningful insights into the complexities of flow dynamics and displacement patterns that are crucial for optimizing hydrogen storage efficiency in saline aquifers and for potential ‘white’ hydrogen production.

Spatiotemporal X-Ray Imaging of Neat and Viscosified CO2 in Displacement of Brine-Saturated Porous Media

Summary CO2 storage in saline aquifers may contribute to a 90% share in preventing emissions to the atmosphere. Due to low CO2 viscosity at the subsurface often found in supercritical (sc) conditions, the injected CO2 may spread quickly at the formation top and increase the probability of leakage. This work relates to improved CO2 storage in saline aquifers by effective viscosification of the sc-CO2 at very low concentrations of engineered oligomers and the effectiveness of slug injection of viscosified CO2 (vis-CO2). We present the results from X-ray computed tomography (CT) imaging to advance the understanding of two-phase CO2-brine flow in porous media and firmly establish the transport mechanisms. X-ray CT imaging of displacement experiments is conducted to quantify the in-situ sc-CO2 saturation spatiotemporally. In neat CO2 injection, gravity override and adverse mobility ratio may result in early breakthrough and low sweep efficiency. We find cumulative brine production from the fraction collector to be lower than X-ray CT imaging at 2 pore volume (PV) injection. The difference between the two is attributed to the solubility of the produced water in the produced CO2 at atmospheric pressure. We show that when the solubility is accounted for, there is a good agreement between direct measurements and in-situ saturation results. There are three reports (two by the same group) that oligomers of 1-decene (O1D) with six repeat units may have marginal CO2 viscosification. The majority of published work by other groups shows that O1D with six repeat units and higher are effective CO2 viscosifiers. In the past, we have demonstrated the effectiveness of an O1D in the displacement of brine by CO2 at a concentration of 1.5 wt%. The effectiveness is examined and identified by three different methods. In this work, we show that the same oligomer is effective at a low concentration of 0.6 wt%. The oligomer slows the breakthrough by 1.6 times and improves the brine production by 34% in the horizontal orientation. X-ray CT imaging results reveal that such a large effect may be from the increase in the interfacial elasticity. We also show that there is no need for continuous injection of the oligomer. A slug of 0.3 PV injection (PVI) of vis-CO2 followed by neat CO2 injection has the same effectiveness as the continuous injection of the vis-CO2. In this work, we also demonstrate the effectiveness of a new engineered molecule at 0.3 wt% that may increase residual trapping by about 35%. The combination of mobility control and residual brine saturation reduction is expected to improve CO2 storage by effective viscosification with low concentrations of oligomers.

Microscopic insights of phase-transition-induced vapor transport enhancement in porous media

Vapor transport in porous media, often associated with liquid-vapor phase change, is an fundamental process in many emerging underground energy storage and extraction processes (i.e., seasonal solar thermal aquifer storage, geothermal extraction, extraterrestrial in-situ water extraction). By jointly using experimental imaging and numerical modeling at the micro-scale, we conduct mechanistic pore scale investigation of capillarity-dominated phase change dynamics and its influence on vapor transport in partially saturated porous rock micromodel. Strongly linked to surface roughness and wettability condition, the capillarity hinders water vaporization from rock surface micro/nano-structures as observed under the environmental scanning electron microscope. By varying the contact angle of 0°, 60°, and 120°, the lattice Boltzmann simulation shows the wettability-dependent vaporization process of capillary-hold water, where pores with hydrophilic surfaces contains significantly more liquid water than that of the hydrophobic ones under the same temperature. When saturated vapor flows through rock porous patterns, capillarity further induces water condensation on the strongly water-wet surfaces. Water condensation, yet forming water bridges/islands and causing the blockage of vapor diffusion, enhances the vapor diffusion ability counterintuitively. The reduction of diffusion path is revealed as the main reason by assessing the local vapor pressure distribution before and after the pore filling by condensate. The findings support the debatable enhancement mechanisms postulated by Philip and de Vries. This work offers the insightful interfacial hydrodynamics of vapor transport in porous media and potentially provides operational guidance for geothermal applications and beyond.

The underground performance analysis of compressed air energy storage in aquifers through field testing

Compressed air energy storage in aquifers (CAESA) has been considered a potential large-scale energy storage technology. However, due to the lack of actual field tests, research on the underground processes is still in the stage of theoretical analysis and requires further understanding. In this study, the first kilometer depth compressed air injection-production field test with multiple flat aquifers is controlled. For all three production rates considered, the minimum pressure drop rate can reach 0.9 MPa/h. An actual wellbore-aquifer-coupled numerical model simulated by T2Well/EOS3 is verified using monitoring data. Due to the limitation imposed by the injection rate, air only flows into the top three sandstone aquifers to build air bubbles. During the production stage, air is first produced from the aquifers and then the air stored in the wellbore is gradually extracted due to the weakened air bubble support effect. Finally, an air-water two-phase occurs and the water level rises in the wellbore. Considering a hypothetical long-term cycle, the designed single aquifer scheme has a better underground performance. A concentrated and larger high air saturation domain can support a stable cycle pressure and above 95% underground efficiency. However, the wellhead pressure drops once water coning happens in the wellbore. With an air bubble replenishment scheme in each cycle, it becomes feasible to maintain stable pressure, ensuring a production pressure difference below 0.94 MPa without water production, over a 100-day cycle in the field. The results provide support for future practical engineering applications.

Dissolving the mystery of subsurface controls on snowmelt–discharge dynamics in karst mountain watersheds using hydrologic timeseries

AbstractStreamflow generation in mountain watersheds is strongly influenced by snow accumulation and melt as well as groundwater connectivity. In mountainous regions with limestone and dolomite geology, bedrock formations can host karst aquifers, which play a significant role in snowmelt–discharge dynamics. However, mapping complex karst features and the resulting surface‐groundwater exchanges at large scales remains infeasible. In this study, timeseries analysis of continuous discharge and specific conductance measurements were combined with gridded snowmelt predictions to characterize seasonal streamflow response and evaluate dominant watershed controls across 12 monitoring sites in a karstified 554 km2 watershed in northern Utah, USA. Immense surface water hydrologic variability across subcatchments, years and seasons was linked to geologic controls on groundwater dynamics. Unlike many mountain watersheds, the variability between subcatchments could not be well described by typical watershed properties, including elevation or surficial geology. To fill this gap, a conceptual framework was proposed to characterize subsurface controls on snowmelt–discharge dynamics in karst mountain watersheds in terms of conduit flow direction, aquifer storage capacity and connectivity. This framework requires only readily measured surface water and climatic data from nested monitoring sites and was applied to the study watershed to demonstrate its applicability for evaluating dominant controls and climate sensitivity.

Fully coupled THM modeling of CO2 sequestration in depleted gas reservoirs considering the mutual solubilities in CO2-Hydrocarbon gas-brine systems

In recent years, CO2 geological sequestration has gained significant traction as a viable solution for mitigating global emissions. However, assessing such processes has been challenging due to its inherent complexity. Given the extensive temporal and spatial scales, numerical modeling has emerged as the most efficient and cost-effective means of evaluating them. At present, most existing models are tailored for CO2 sequestration in saline aquifers. There are relatively few models available for depleted gas reservoirs, and only a fraction of them possess the capability to account for geomechanical coupling or complex natural gas compositions.CO2 sequestration in depleted gas reservoirs is considered a promising technique for combating global warming. The use of depleted gas reservoirs has several advantages over saline aquifers, such as the availability of existing facilities and the proven capacity and stability of gas storage. It is believed that CO2 storage in depleted petroleum reservoirs can provide intermediate-scale storage until large-scale storage in saline aquifers becomes mature.Here we propose an Equation of State (EOS) module for CO2 sequestration in depleted gas reservoirs or CO2-enhanced gas recovery. It takes into consideration the mutual solubilities in the CO2-hydrocarbon gas-brine system based on the equality of the chemical potentials of the aqueous and non-aqueous phases. In such a way, it can properly address CO2 dissolution into brine when hydrocarbon gas is present. Hydrocarbon gas includes methane, ethane, and propane. It employs well-recognized approaches to calculate the thermodynamic properties of the gaseous and aqueous phases. This EOS module has been applied to our in-house simulator, TOUGH2-CSM, to enable thermo-hydrological-mechanical modeling. Our research could fill the gap and provide a reference for future studies in this regard.

Effect of permeability and density difference on convective mixing and storage of CO2 in saline aquifers

The density-driven natural convection is believed to have a positive impact on CO2 storage in saline aquifers. In this regard, studying the parameters that influence the onset of convection is crucial for determining the optimal storage location. Here, we conducted a numerical analysis to investigate how the permeability of the porous medium and the density difference between the brine and CO2-brine mixture affect the mixing efficiency, speed, and development of convective fingers. Results showed that greater permeability and density difference result in a faster onset of convection; hence, fluid velocity and mixing efficiency will increase. Moreover, considering CO2 dissolution based solely on Rayleigh number is not entirely accurate. In addition, if there are different permeability and density difference values, even with a constant Rayleigh number, the mixing of CO2 and brine would not be the same.

Integrated Black Oil Modeling for Efficient Simulation and Optimization of Carbon Storage in Saline Aquifers

Integrated Black Oil Modeling for Efficient Simulation and Optimization of Carbon Storage in Saline Aquifers

Laboratory determination of hydrogen/methane dispersion in rock cores for underground hydrogen storage

Underground hydrogen storage in saline aquifers is a promising way to store large amounts of energy. Utilization of gas cushion enhances the deliverability of the storage and increases the volume of recovery gas. The key factor for the cushion characterization is cushion gas and storage gas mixing which can be used for simulation of mixing zone evolution. In this work coreflooding setup utilizing Raman spectroscopy is built and used for dispersion coefficient determination. Berea sandstone rock core is used as a test sample for setup validation and core entry/exit effects estimation. Dispersion for hydrogen and methane as displacing fluids is determined for 4 locations perspective for hydrogen storage in Poland is found. Reservoir structures most suitable for pure hydrogen or hydrogen/methane blend storage are selected.