Brine Rock Interactions Research Articles

Potential for 50% Mechanical Strength Decline in Sandstone Reservoirs Due to Salt Precipitation and CO2–Brine Interactions During Carbon Sequestration

AbstractPredictive modeling of CO2 storage sites requires a detailed understanding of physico-chemical processes and scale-up challenges. Dramatic injectivity decline may occur due to salt precipitation pore clogging in high-salinity aquifers during subsurface CO2 injection. This study aims to elucidate the impact of CO2-induced salt crystallization in the porous medium on the geomechanical properties of reservoir sandstones. As the impact of salt precipitation cannot be isolated from the precursor interactions with CO2 and acidified brine, we present a comprehensive review and discuss CO2 chemo-mechanical interactions with sandstones. Laboratory geochemical CO2–brine–rock interactions at elevated pressures and temperatures were conducted on two sandstone sets with contrasting petrophysical qualities. Interaction paths comprised treatment with (a) CO2-acidified brine and (b) supercritical injection until brine dry-out, salt crystallization, and growth. Afterward, the core samples were tested in a triaxial apparatus at varying stresses and temperatures. The elastic moduli of intact, CO2-acidified brine treated, and salt-affected sandstones were juxtaposed to elucidate the geochemical–geomechanical-coupled impacts and identify the extent of crystallization damages. The salt-affected sandstones showed a maximum of 50% reduction in Young’s and shear moduli and twice an increase in Poisson’s ratio compared to intact condition. The deterioration was notably higher for the tighter reservoir sandstones, with higher initial stiffness and lower porosity–permeability. We propose two pore- and grain-scale mechanisms to explain how salt crystallization contributes to stress localization and mechanical damage. The results highlight the potential integrity risk imposed by salt crystallization in (hyper)saline aquifers besides injectivity, signaling mechanical failure exacerbated by pressure buildup.

Geochemistry in Geological CO2 Sequestration: A Comprehensive Review

The increasing level of anthropogenic CO2 in the atmosphere has made it imperative to investigate an efficient method for carbon sequestration. Geological carbon sequestration presents a viable path to mitigate greenhouse gas emissions by sequestering the captured CO2 deep underground in rock formations to store it permanently. Geochemistry, as the cornerstone of geological CO2 sequestration (GCS), plays an indispensable role. Therefore, it is not just timely but also urgent to undertake a comprehensive review of studies conducted in this area, articulate gaps and findings, and give directions for future research areas. This paper reviews geochemistry in terms of the sequestration of CO2 in geological formations, addressing mechanisms of trapping, challenges, and ways of mitigating challenges in trapping mechanisms; mineralization and methods of accelerating mineralization; and the interaction between rock, brine, and CO2 for the long-term containment and storage of CO2. Mixing CO2 with brine before or during injection, using microbes, selecting sedimentary reservoirs with reactive minerals, co-injection of carbonate anhydrase, and enhancing the surface area of reactive minerals are some of the mechanisms used to enhance mineral trapping in GCS applications. This review also addresses the potential challenges and opportunities associated with geological CO2 storage. Challenges include caprock integrity, understanding the lasting effects of storing CO2 on geological formations, developing reliable models for monitoring CO2–brine–rock interactions, CO2 impurities, and addressing public concerns about safety and environmental impacts. Conversely, opportunities in the sequestration of CO2 lie in the vast potential for storing CO2 in geological formations like depleted oil and gas reservoirs, saline aquifers, coal seams, and enhanced oil recovery (EOR) sites. Opportunities include improved geochemical trapping of CO2, optimized storage capacity, improved sealing integrity, managed wellbore leakage risk, and use of sealant materials to reduce leakage risk. Furthermore, the potential impact of advancements in geochemical research, understanding geochemical reactions, addressing the challenges, and leveraging the opportunities in GCS are crucial for achieving sustainable carbon mitigation and combating global warming effectively.

Recent Advances in Geochemical and Mineralogical Studies on CO2–Brine–Rock Interaction for CO2 Sequestration: Laboratory and Simulation Studies

The urgent need to find mitigating pathways for limiting world CO2 emissions to net zero by 2050 has led to intense research on CO2 sequestration in deep saline reservoirs. This paper reviews key advancements in lab- and simulation-scale research on petrophysical, geochemical, and mineralogical changes during CO2–brine–rock interactions performed in the last 25 years. It delves into CO2 MPD (mineralization, precipitation, and dissolution) and explores alterations in petrophysical properties during core flooding and in static batch reactors. These properties include changes in wettability, CO2 and brine interfacial tension, diffusion, dispersion, CO2 storage capacity, and CO2 leakage in caprock and sedimentary rocks under reservoir conditions. The injection of supercritical CO2 into deep saline aquifers can lead to unforeseen geochemical and mineralogical changes, possibly jeopardizing the CCS (carbon capture and storage) process. There is a general lack of understanding of the reservoir’s interaction with the CO2 phase at the pore/grain scale. This research addresses the gap in predicting the long-term changes of the CO2–brine–rock interaction using various geochemical reactive transport simulators. Péclet and Damköhler numbers can contribute to a better understanding of geochemical interactions and reactive transport processes. Additionally, the dielectric constant requires further investigation, particularly for pre- and post-CO2–brine–rock interactions. For comprehensive modeling of CO2 storage over various timescales, the geochemical modeling software called the Geochemist’s Workbench was found to outperform others. Wettability alteration is another crucial aspect affecting CO2–brine–rock interactions under varying temperature, pressure, and salinity conditions, which is essential for ensuring long-term CO2 storage security and monitoring. Moreover, dual-energy CT scanning can provide deeper insights into geochemical interactions and their complexities.

Evaluation of SC-CO2–brine on the micro-mechanical properties of lamina shales by micro-scratch test

The mechanism of SC-CO2–brine–rock interaction (SCBRI) and its effect on the mechanical properties of shale are crucial for shale oil development and CO2 sequestration. To clarify the influence of SCBRI on the micromechanics of shale, the lamina and matrix of shale were saturated with SC-CO2–brine for 2, 4, 6, and 8 days, respectively. The micro-scratch technique was then used to measure the localized fracture toughness before and after SC-CO2–brine saturation. Combining the micro-scratch results with SEM-QEMSCAN-EDS analysis, the differences in mineral composition and mechanical properties of lamina (primarily composed of carbonate minerals) and matrix (primarily composed of clay minerals) were studied. The QEMSCAN analysis and micro-scratch results indicate distinct mineralogical compositions and mechanical properties between the lamina and the matrix. The results showed that: (1) SCBRI leads to the decrease in carbonate mineral content and the significant increase in matrix porosity and laminar cracks. In addition, the damage degree increased at saturation for 6 days. (2) SCBRI weakens the mechanical properties of shale. The scratch depth of laminar and matrix increased by 34.38% and 1.02%, and the fracture toughness decreased by 34.38% and 13.11%. It showed a trend of first increasing and then decreasing. (3) SCBRI enhances the plastic deformation behavior of shale, and the plastic index of lamina and matrix increases by 18.75% and 21.58%, respectively. These results are of great significance for evaluating the mechanical properties of shale oil and gas extraction by CO2.

Influence of the CO2–brine–rock interaction on the plastic zone of sandstone

During the long-term CO2 storage process, the CO2–brine–rock interaction (CBRI) may change the elastic-plastic behaviors of sandstone reservoirs, potentially leading to rock damage and CO2 leakage. A good understanding of the influence of the CBRI on the plastic zone of sandstone is crucial for evaluating the rock fracturing processes. In this paper, three-point bending tests were conducted under both monotonic and cyclic loading conditions, and the digital image correlation technique was used to analyze the elastic and plastic characteristics of the samples. The experimental results showed that the CBRI decreases the yield strength and corresponding crack mouth opening displacement by 25 % and 65%, respectively, thus increasing the probability of fracturing. Additionally, it was found that the CBRI enlarges the plastic zone by about 20 %. The size of the theoretical plastic zone in the sandstone sample for different loads was determined, and the ratio of the plastic zone size in the samples with CO2–brine saturation to that without CO2–brine saturation was found to be about 1.18. Finally, the mesoscale factors affecting the plastic zone size after CO2–brine saturation were analyzed. This study helps to understand the effect of the elastic-plastic behavior of sandstone on reservoir stability during long-term CO2 storage.

Application of hierarchical cluster analysis and principal component analysis to identify compositional trends of brine in crystalline basements and sedimentary basins

The present study identifies distinct geochemical signatures of deep brines originating from crystalline basements and sedimentary basins. A corresponding conceptual hydrogeochemical model is developed outlining the evolution of crystalline and sedimentary brines. The combined application of Hierarchical Cluster Analysis and Principal Component Analysis allowed the identification of evolutionary trends of groundwater towards crystalline and sedimentary brines. Using 308 brine samples from the existing literature, eight chemical species were considered in the analysis: sodium, magnesium, potassium, calcium, strontium, chlorine, sulfate, and bromine, from which two salinity evolution pathways towards common Ca–Cl brines were derived: (1) the evolution of crystalline brines, which evolved from recharge water to brine through hydration of silicates, is described by the linear equation Ca = −1610 + 0.4*Cl; and (2) the evolution of sedimentary brines, which evolved from recharge water to brine through dissolution and precipitation of halite, is described by the linear equation Cl/Br = 103 + Na/Br. We also discuss differences in water isotopes, and in lithium and boron concentrations which directly reflect various temperature-dependent processes that control the evolution of sedimentary and crystalline brines. This leads to development of a discriminatory graphical tool using B/Br and Li/Br ratios, with crystalline brines having B/Br and Li/Br ratios below 0.01 and sedimentary brines above 0.01. Our results improve our understanding of deep crustal brine evolution through brine-rock interaction.

Effects of SiO2 Nanoparticles on Wettability and CO2–Brine–Rock Interactions in Carbonate Reservoirs: Implications for CO2 Storage

Effects of SiO₂ Nanoparticles on Wettability and CO₂–Brine–Rock Interactions in Carbonate Reservoirs: Implications for CO₂ Storage

Studying the impact of reservoir temperature, water salinity and CO2 dryness on CO2 injectivity during geological CO2 sequestration

Carbon capture and storage (CCS) is proved to be effective measure for reducing CO2 emissions. whilst the world still highly depends on the use of fossil fuel energy, this method is necessary for reaching the world’s 1.5 °C goal. Saline aquifers among all possible underground formations are most common targeted ones for CO2 storage due to their frequent presence, and large storage capacity. However, this storage option suffers from sufficient well injectivity to inject large volumes of CO2 at acceptable rates through a minimum number of wells. The injectivity impairment/reinforcement happens through mineral dissolution, fine particle movement, salt precipitation and hydrate formation (known so far). Each of these mechanisms will be more dominant in injectivity alteration at different distance from the injection point depending on reservoir pressure and temperature, formation water salinity, rock mineralogy, and flow rate of CO2 injection as well as its dryness. In this study we have chosen a commercial software Eclipse 300 together with an open-source code to investigate the impact of formation characteristics, CO2 -Brine-Rock interaction, pressure, temperature as well as injection rate on injectivity alteration. The goal for this work is to provide a workflow which can help predicting injectivity alteration using the existing tools. Simulation results show that permeability is affected severely by salt precipitation during CO2 injection. Combined static and dynamic parameter study demonstrate that the injection rate plays a crucial role in size and expansion of CO2 plume as well as growth rate of dry out zone length, amount of salt precipitation and length of equilibrium region. The higher the injection rate, the quicker activation of the capillary and gravity force which leads to drag more brine to near well-bore resulting in higher volume fraction of salt precipitation. However, low injection rate could result in smaller CO2 plume, shorter dry out zone and longer equilibrium region in term of distance from injection point. Thus, optimizing the injection rate regarding reservoir parameters i.e., temperature, pressure and in-situ salinity, will lead to higher storage capacity as well as well performance and maintenance.

Effect of CO2-Brine-Rock Interactions on the Pore Structure of the Tight Sandstone during CO2 Flooding: A Case Study of Chang 7 Member of the Triassic Yanchang Formation in the Ordos Basin, China.

CO2 flooding is an effective technique to enhance oil recovery from tight sandstone reservoirs. The CO2-rich fluid reacts with the in situ minerals and results in the corrosion and precipitation of minerals in the sandstone, affecting the connectivity and morphological features of pores. However, the diagenesis of the tight sandstone is complex, and the structural modification behavior and mechanism in different lithofacies of tight sandstone during CO2 flooding are still unclear. This study combined CO2 flooding, thin-section casting, scanning electron microscopy, nuclear magnetic resonance, X-ray diffraction, and fractal analysis methods to investigate the changes in the pore structure of tight sandstone after CO2 flooding. The results show that the cement of the tight sandstone is complex and diverse. The tight sandstone can be divided into two types of lithofacies: clay cementation (CL) and ferrocalcite cementation (CA). The mineralogical alterations occur differently in each lithofacies of tight sandstone. Alterations in the cement minerals affect the pores morphology of tight sandstone depending on their mineralogical structure and texture, and the CO2 flooding mainly changes the micromorphology and heterogeneity of large pores. Clay minerals dominate the cement in the CL lithofacies of tight sandstone. The dissolution mainly occurs in small pores because the precipitation of new minerals and exfoliation of skeleton particles partially block large pores and transform them into small pores. Thus, the number of small pores of CL lithofacies increases while the number of large pores decreases. Such a phenomenon hinders the increase in porosity and permeability. On the other side, in the CA lithofacies of tight sandstone, the cement is dominated by ferrocalcite, and the dissolution of ferrocalcite is the primary mechanism of mineralogical alteration. As the ferrocalcite dissolution expands, it creates new flow paths, improving the connectivity of pores. The petrophysical properties of CA lithofacies improve significantly after CO2 flooding. There is a crucial need to study the changes in diagenetic characteristics of tight sandstone due to CO2 flooding. Such type of study provides insights related to the improvement and evaluation of the development of tight sandstone reservoirs during CO2 flooding.

A Comprehensive Simulation Study of Physicochemical and Geochemical Interactions on Immiscible CO2-LSWAG Injection in Carbonates

Low-salinity water-alternating-CO2 (CO2-LSWAG) injection has been widely studied and employed due to its capability to promote enhanced oil recovery (EOR). However, there is no consensus on the dominant mechanisms for oil recovery in carbonates due to the extreme complexity of the oil–brine–rock interactions. This work proposes a comparative investigation of the physicochemical and geochemical effects of continuous CO2 and CO2-LSWAG immiscible injections on oil recovery in a carbonate core. Simulations were carried out using oil PVT properties and relative permeability experimental data from the literature. A comparison of SO42− and Mg2+ as interpolant ions, oil, water and gas production, pressure, and rock and fluid properties along the core and in the effluent was made. The results show a high recovery factor for CO2 (62%) and CO2-LSWAG (85%), even in immiscible conditions. The mineral dissolution and porosity variations were more pronounced for CO2-LSWAG than CO2. The simulation results showed that Mg2+ as an interpolant improves oil recovery more than SO42− because Mg2+ concentration in the aqueous phase after LSW injection leads to relative permeability values, which are more favorable.

Surface Energy and Wetting Behavior of Dolomite in the Presence of Carboxylic Acid-Based Deep Eutectic Solvents.

This study endeavors to apply experimental and theoretical analyses to assess the viability of wettability alteration for two carboxylic acid-based deep eutectic solvents (DESs). To prepare these chemicals, oxalic acid and citric acid were used as hydrogen bond donors mixed with choline chloride as the hydrogen bond acceptor in an equimolar ratio. In the theoretical part, dolomite and crude oil were characterized using a three-phase setup. Then, the adhesion propensity of brines/crude oil toward dolomite was evaluated by calculating the work of adhesion. Contact angle and interfacial tension measurements were conducted in the experimental part to investigate the impact of chemicals on brine-crude oil and brine-rock interactions. Results revealed that the oxalic acid-based DES outperformed the citric acid-based DES in terms of interfacial tension reduction. In addition, choline chloride/oxalic acid (1:1) could effectively restore the wettability of the dolomite sample to its original state with a wettability alteration index of 82%. Theoretical calculations also confirmed the wettability alteration potential of DESs. Finally, a correlation was proposed to predict the contact angle of brine on the dolomite surface in the presence of crude oil using surface-energy components of brine, crude oil, and dolomite.

Propagation of mineral dissolution waves driven by cation exchange in low salinity waterflooding

Low salinity waterflooding (LSWF) is an emerging improved/enhanced oil recovery (IOR/EOR) technique with an applicability in both sandstone and carbonate reservoirs. The underlying recovery mechanism of LSWF is still not completely understood due to the multiscale complex interactions occurring in crude oil/brine/rock (COBR) systems. There are several proposed mechanisms, where mineral dissolution is the most prominent among them. The objective of this paper is to study the brine-rock interactions, and understand the propagation of mineral dissolution waves in LSWF processes through theoretical analysis and geochemical modeling. A reactive transport geochemical modeling using PHREEQC (pH-REdox-EQuilibrium in C programing language) simulator has been carried out to understand the interplay of different geochemical effects such as multivalent cation exchange, and mineral dissolution during flow and transport in LSWF. The presence of clays and carbonate cements is most common in sandstone reservoirs, while some carbonate reservoirs also contain clay minerals. Therefore, a core scale geochemical model containing clay and carbonate minerals as active minerals for brine-rock interactions is chosen as a representative analog for most sandstone reservoirs and some of the carbonate reservoirs in this study. The results show that LSWF disturbs the geochemical equilibrium between the formation brine and reservoir rock minerals thereby causing the carbonate mineral dissolution. It is also inferred that without the cation exchange effect of clay minerals, carbonate mineral dissolution effects are local and they occur only close to the inlet of a core plug sample during LSWF. The new equilibrium between brine and rock minerals is then established rapidly. In the presence of clay minerals and cation exchange effect, the clay surfaces were found to preferentially adsorb divalent cations over monovalent cations during LSWF. Such cation exchange process softens the injected low salinity brine to maintain the brine under saturation with respect to carbonate minerals, and subsequently propagates carbonate mineral dissolution waves across the full length of the core sample. The novelty of this work is that it proposes and demonstrates a new geochemical based mechanism for LSWF, i.e., the propagation of mineral dissolution waves driven by the cation exchange process in the reservoir. The identified mechanism has several practical implications in the field: (1) carbonate mineral dissolution and the associated local pH increase can extend from local to reservoir scale, (2) the resulting mineral dissolution effectively releases the oil attached to the mineral surfaces, and (3) increasing the pH modifies the surface charges of both the rock and crude oil to be more negatively charged. The resultant electrostatic repulsion between the two interfaces would increase the water-wetness of rock surfaces to achieve higher improved oil recovery in LSWF.

Comprehensive sensitivity analysis on static and dynamic reservoir parameters impacting near wellbore injectivity during CO2 sequestration

Carbon capture and storage (CCS) is proved to be effective measure for reducing CO2 emissions. whilst the world still highly depends on the use of fossil fuel energy, this method is necessary for reaching the world’s 1.5 °C goal.In CCS, CO2 is hindered from entering the atmosphere by capturing it from sources of emission and storing it in geological formation. Saline aquifers among all possible underground formations are most common targeted ones for CO2 storage due to their frequent presence, and large storage capacity. However, this storage option suffers from sufficient well injectivity to inject large volumes of CO2 at acceptable rates through a minimum number of wells.The injectivity impairment / reinforcement happens through mineral dissolution, fine particle movement, salt precipitation and hydrate formation (known so far). Each of these mechanisms will be more dominant in injectivity alteration at different distance from the injection point depending on reservoir pressure and temperature, formation water salinity, rock mineralogy, and flow rate of CO2 injection as well as its dryness.Incorporating all the finding into radial flow near wellbore will help gaining insight into the resultant of injectivity changes over time and distant from injection point. In this study we have chosen Eclipse 300 together with an open-source code to investigate the impact of formation characteristics, CO2 -Brine-Rock interaction, pressure, temperature as well as injection rate on injectivity alteration. The goal for this work is to provide a workflow which can help predicting injectivity alteration using the existing tools.Simulation results show that the high homogenous horizontal permeability in combination with vertical flow baffles in the formation (among all other parameters) has positive impact on storage capacity by increasing residual trapping. However, permeability is affected severely by salt precipitation during CO2 injection. Combined static and dynamic parameter study demonstrate that the injection rate plays a crucial role in size and expansion of CO2 plume as well as growth rate of dry out zone length, amount of salt precipitation and length of equilibrium region. The higher the injection rate, the quicker activation of the capillary and gravity force which leads to drag more brine to near well-bore resulting in higher volume fraction of salt precipitation. However, low injection rate could result in smaller CO2 plume, shorter dry out zone and longer equilibrium region in term of distance from injection point.

CO2–Brine–rock interaction and sequestration capacity in carbonate reservoirs of the Tahe Oilfield, Xinjiang, China

AbstractThe characteristics of each carbonate reservoir are greatly different, and current databases are insufficient to support engineering scheme design and optimization of carbon dioxide (CO2) sequestration and enhanced oil recovery. In this paper, the behavior of CO2‐brine‐rock interactions was investigated under supercritical CO2 (50°C and 8.5 MPa) conditions. Five experiments were carried out, including CO2 solubility in brine, mass loss analysis by static reaction of CO2–brine–rock, mineralogical composition analysis by X‐ray diffraction (XRD), core surface morphology analysis by scanning electron microscopy (SEM), and wettability alteration by contact angle analysis. The experimental results showed that: (a) the CO2 solubility in brine increases with increasing pressure, but it increases slowly and gradually reaches equilibrium; (b) the mass loss of carbonate increases with reaction time, but its increments decrease with reaction time; (c) the calcite content gradually decreases and the quartz content slightly increases with reaction time, as evidenced by XRD analysis; (d) based on SEM image analysis, calcite was dissolved into brine by carbonic acid to make the pores larger, and then subsequent precipitation made the pores smaller; and (e) the carbonate rock surface became more water‐wet after CO2–brine–rock interaction experiments due to surface corrosion and increased quartz content. Using the experimental results, a mathematical model was developed to predict CO2 sequestration capacity under reservoir conditions. The results suggest that CO2 solubility in brine was the main aspect compared with mineral trapping in carbonate reservoirs, and CO2 sequestration capacity increased with increasing temperature and pressure. © 2022 Society of Chemical Industry and John Wiley & Sons, Ltd.

CO2–brine–rock interactions altering the mineralogical, physical, and mechanical properties of carbonate-rich shale oil reservoirs

The introduction of CO2 in deep formations triggers complex geochemical/geophysical processes, affecting CO2 geological storage safety and enhancing oil/gas recovery. Previous studies have mainly focused on the long-term geochemical reactions in reservoirs with low carbonate content (<30%). However, the short-term CO2–brine–rock interaction in carbonate-rich formations has been ignored. In this study, soaking experiments were conducted, followed by a series of multi-scale tests, to systematically quantify the mineralogical, physical, and mechanical properties of carbonate-rich shale reservoirs after CO2 fracturing and to reveal the alteration mechanisms. The results indicate that the CO2–brine–rock interaction shows a high preference for dissolving carbonate, followed by nonpure feldspars, and then pure feldspars. Carbonate may impede the dissolution of pure feldspars but has little impact on nonpure ones. With carbonate content and reaction time increases, the porosity and permeability were improved by as high as 105% and 382.1%, respectively, while the hardness, tensile strength, and toughness were weakened remarkably. Fracture closure may occur at severely softened fracture areas with a surface hardness lower than 0.07 GPa, when the reaction time lasts more than 168 h. This study implies that a long shut-in stage after CO2 fracturing in carbonate-rich shale reservoirs should be avoided.

A Review of the Studies on CO2–Brine–Rock Interaction in Geological Storage Process

CO2–brine–rock interaction impacts the behavior and efficiency of CO2 geological storage; a thorough understanding of these impacts is important. A lot of research in the past has considered the nature and impact of CO2–brine–rock interaction and much has been learned. Given that the solubility and rate of mineralization of CO2 in brine under reservoir conditions is slow, free and mobile, CO2 will be contained in the reservoir for a long time until the phase of CO2 evolves. A review of independent research indicates that the phase of CO2 affects the nature of CO2–brine–rock interaction. It is important to understand how different phases of CO2 that can be present in a reservoir affects CO2–brine–rock interaction. However, the impact of the phase of CO2 in a CO2–brine–rock interaction has not been given proper attention. This paper is a systematic review of relevant research on the impact of the phase of CO2 on the behavior and efficiency of CO2 geological storage, extending to long-term changes in CO2, brine, and rock properties; it articulates new knowledge on the effect of the phase of CO2 on CO2–brine–rock behavior in geosequestration sites and highlights areas for further development.

High-Resolution Topographic and Chemical Surface Imaging of Chalk for Oil Recovery Improvement Applications

Chalk is a very fine-grained carbonate and can accommodate high porosity which is a key characteristic for high-quality hydrocarbon reservoirs. A standard procedure within Improved Oil Recovery (IOR) is seawater-injection which repressurizes the reservoir pore pressure. Long-term seawater-injection will influence mineralogical processes as dissolution and precipitation of secondary minerals. These secondary minerals (&lt;1 micrometer) precipitate during flooding experiments mimicking reservoir conditions. Due to their small sizes, analysis from traditional scanning electron microscopy combined with energy dispersive X-ray spectroscopy is not conclusive because of insufficient spatial resolution and detection limit. Therefore, chalk was analyzed with high-resolution imaging by helium ion microscopy (HIM) combined with secondary ion mass spectrometry (SIMS) for the first time. Our aim was to identify mineral phases at sub-micrometer scale and identify locations of brine–rock interactions. In addition, we wanted to test if current understanding of these alteration processes can be improved with the combination of complementary imaging techniques and give new insights to IOR. The HIM-SIMS imaging revealed well-defined crystal boundaries and provided images of excellent lateral resolution, allowing for identification of specific mineral phases. Using this new methodology, we developed chemical identification of clay minerals and could define their exact location on micron-sized coccolith grains. This shows that it is essential to study mineralogical processes at nanometer scale in general, specifically in the research field of applied petroleum geology within IOR.

Quantitative analysis of CO2 miscible flooding in tight formation at pore scale applying nuclear magnetic resonance

The CO2 miscible flooding in Baikouquan tight formation was thoroughly investigated under reservoir condition of 37 MPa and 89 °C. The low-field nuclear magnetic resonance (NMR) system was used to measure the real time oil saturation under high-temperature and high-pressure environment. The results show that the recovery factors of large, medium and small pores are 66.18%, 45.71%, and 12.71%, respectively. A complementary investigation of CO2–brine–rock interaction was performed, which indicate that the small pore throats blockage during the displacement process is the main reason for low recovery in small pores.

CO2 storage in carbonate rocks: An experimental and geochemical modeling study

Carbon dioxide storage in geological formations is one of the mature strategies developed for controlling global warming. This paper represents a comprehensive experimental and geochemical modeling study to analyze CO2-brine-rock interactions in a carbonate rock containing calcite and dolomite minerals. PHREEQC geochemical package has been applied for modeling the geochemical reactions in the studied porous media. Firstly, dynamic experiments are performed to calibrate the geochemical model. Then, static experiments are conducted to study the geochemical reactions in the CO2-brine-rock interaction system. This study contributes to analyzing the precipitation-dissolution and ion exchange mechanisms in the CO2-brine- carbonate rock reactions during carbon dioxide storage. The purpose of the present paper is providing a scientific basis to judge surface CO2 loading in carbonate reservoirs. Results of the present study show that brine-rock interaction increases the dissolution of carbon dioxide gas in the aqueous phase. It is also demonstrated that carbonate ions can attach to the minerals' surface through the ion exchange mechanism. Among the surface ion exchangers, >CaHCO3 contains the maximum amount of carbonate ion. At the high pressures, amount of the carbon dioxide stored on the minerals' surface is almost independent of the pressure variation.

Incorporation of geochemical, geometrical and intermolecular interactions into modelling of scale removal in a capillary microchannel

Along with scale deposition on rock surfaces during brine-rock interactions, it is likely that the formed deposit may be dislodged due to shear stress exerted by flowing brine. This study presents a simplified model for removal of gypsum scale from rock surfaces of anhydrite, calcite, dolomite, and sandstone during the interaction with brines of 3000 mg/L and 6000 mg/L of [Ca2+] within a capillary microchannel. To do so, the intermolecular interaction energies primarily Lewis acid-base adhesion energy for gypsum scale on various rocks were firstly characterized in order to develop the surface energy-based correlation of deposit strength for the formed scale layer. The kinetic and hydrodynamic patterns of scale removal were then attained based on the assumption of asymptotic behaviour for the net mass of scale at the end of the scaling process. The results showed that the removal rate initially increases profoundly followed by a low-sloped increment. Higher flow velocity increases the removal flux of gypsum scale from different rock surfaces as much as 2.4- and 2.2-fold for the brine salinity of 3000 mg/L and 6000 mg/L of [Ca2+], respectively. Furthermore, higher brine salinity in terms of [Ca2+] would lead to more removal of gypsum scale from the rock surfaces of anhydrite followed by carbonate and sandstone reservoir rock surfaces approximately 1.9-fold at the lower flow velocity and 1.8-fold for the higher brine flow velocity, respectively.