Search Results (28)

In deep brine oil and gas injection–production operations, the combined long-term effects of brine and carbon dioxide on rock mechanical properties are not clear. In order to solve this problem, the influence of long-term salt–CO₂ environment on the mechanical properties of sandstone is discussed. The mechanism of interaction evolution and fracture propagation was studied in detail by NMR, the triaxial compression test and a CT scan. The results show that the triaxial compressive strength and mass of sandstone decrease first and then increase with the prolonging of soaking time. The proportion of micropores first decreased and then increased, while the proportion of medium and large pores first increased and then decreased. The pores obtained by Avizo’s segmentation of the threshold value of CT sections first increased and then decreased, and the fractal dimensions obtained first increased and then decreased. In particular, the calcium ions in the immersion solution increased first and then decreased. The reaction rate was obtained and verified according to the changes in calcium carbonate mass and calcium ion mineralization at different times. The failure mode of the sample gradually changed from /-shaped failure to V-shaped composite failure, then to local /-shaped failure, and finally to X-shaped composite failure. On this basis, the process of sandstone was divided into the dissolution stage, precipitation stage and secondary dissolution stage, and the rock microstructure change model under a salt–CO₂ environment was established. The mechanics, temperature, chemical interaction mechanism and fracture propagation mechanism of sandstone under a salt–CO₂ environment are discussed. Full article

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. Full article

Minerals are the chief constituents of rocks and have varied properties, such as the surface area, surface charge, site density, etc. Hence, numerous interactions are bound to occur in a reservoir during rock–fluid (i.e., rock, crude oil and brine) interactions. This study seeks to assess the role of the mineralogical composition in the wettability of sandstone rocks (SRs) and mineral mixture (MM) using both surface complexation modeling (SCM) and a flotation test. From the considered sandstone rocks, both the experimental results and the simulated counterparts revealed that the SRs were preferentially hydrophilic. For the MM, when the mass fraction of the hydrophobic mineral was increased, the affinity of the MM became slightly hydrophobic, and vice versa. For the dominant sandstone reservoir rock minerals with predominantly negatively charged surfaces, negligible oil adsorption took place due to the interfacial repulsive forces at the oil–brine and mineral–brine interfaces. For the MM with low calcite content, the wetting preference was influenced by the mineral with a prominent surface area. Our developed model portrayed that the main mechanism of oil adhesion onto sandstone minerals was divalent cation bridging. Nonetheless, adhesion of carboxylate (>COO⁻) onto the illite, montmorillonite and calcite sites also took place, with the latter being more pronounced. Full article

Green solvents like DES have gained tremendous attention and have been employed for many applications, as industries are now geared toward adopting green materials technologies to contain the effects of climate change, environmental pollution, and global warming. They have found application and use in enhanced oil recovery in the petroleum industry as surface active materials, among others. However, there is a need to be able to select, screen, and rank the best performance DESs among a large combination of HBA and HBD capable of forming DESs that can perform for enhanced oil recovery (EOR), viz–viz, additional oil recovery. In this study, choline chloride (CHCL)-based DESs, the most employed DES in EOR, are screened for their ability to reduce interfacial tension, adsorption capacities, and oil enhancement. We innovate a screening criterion using molecular descriptors obtained from the interaction of the DES with species (rock, water, oil, and brine) used in the reservoir. Our findings indicate that the correlation of experimental properties with calculated descriptors can be used to predict the overall EOR performance. Our study contributes to valuable insights into the screening of DESs theoretically to be used for EOR. It also can be employed as a quick check to reduce trial and error during the experimental selection of energetically stable DESs in the laboratory for their potential application for EOR performance in a cost-effective manner. Full article

Emission reduction in the main greenhouse gas, CO₂, can be achieved efficiently via CO₂ geological storage and utilization (CCUS) methods such as the CO₂ enhanced oil/water/gas recovery technique, which is considered to be an important strategic technology for the low-carbon development of China’s coal-based energy system. During the CCUS, the thermodynamic properties of the CO₂–water–rock system, such as the interfacial tension (IFT) and wettability of the caprock, determine the injectability, sealing capacity, and safety of this scheme. Thus, researchers have been conducting laboratory experiments and modeling work on the interfacial tension between CO₂ and the water/brine, wettability of caprocks, the solubility of gas–liquid binary systems, and the pH of CO₂-saturated brine under reservoir temperature and pressure conditions. In this study, the literature related to the thermodynamic properties of the CO₂–water–rock system is reviewed, and the main findings of previous studies are listed and discussed thoroughly. It is concluded that limited research is available on the pH of gas-saturated aqueous solutions under CO₂ saline aquifer storage conditions, and less emphasis has been given to the wettability of the CO₂–water/brine–rock system. Thus, further laboratory and modeling research on the wettability alternations of caprock in terms of molecular dynamics is required to simulate this phenomenon at the molecular level. Moreover, simplified IFT and solubility prediction models with thermodynamic significance and high integrity need to be developed. Furthermore, interaction mechanisms coupling with multi-factors associated with the gas–liquid–solid interface properties and the dissolution and acidification process need to be explored in future work. Full article

Polymer flooding is one of the most widely used and effective enhanced oil recovery techniques. It can improve the macroscopic sweep efficiency of a reservoir by controlling the fractional flow of water. The applicability of polymer flooding for one of the sandstone fields in Kazakhstan was evaluated in this study and polymer screening was carried out to choose the most appropriate polymer among four hydrolyzed polyacrylamide polymer samples. Polymer samples were prepared in Caspian seawater (CSW) and assessed based on rheology, thermal stability, sensitivity to non-ionic materials and oxygen, and static adsorption. All the tests were performed at a reservoir temperature of 63 °C. Based on the results of the screening study, tolerance of a polymer towards high-temperature reservoir conditions, resistance to bacterial activity and dissolved oxygen present in make-up brine, chemical degradation, and reduced adsorption on rock surface were considered the most important screening parameters. As a result of this screening study, one out of four polymers was selected for the target field as it showed a negligible effect of bacterial activity on thermal stability. The results of static adsorption also showed 13–14% lower adsorption of the selected polymer compared to other polymers tested in the study. The results of this study demonstrate important screening criteria to be followed during polymer selection for an oilfield as the polymer should be selected based on not only polymer characteristics but also the polymer interactions with the ionic and non-ionic components of the make-up brine. Full article

An oil recovery technique, different composition waterflooding (DCW), dependent on the varying injected water composition has been the subject of various research work in the past decades. Research work has been carried out at the lab, well and field scale whereby the introduction of different injection water composition vis-a-vis the connate water is seen to bring about improvements in the oil recovery (improvements in both macroscopic and microscopic recoveries) based on the chemical reactions, while being sustainable from ease of implementation and reduced carbon footprint points of view. Although extensive research has been conducted, the main chemical mechanisms behind the oil recovery are not yet concluded upon. This research work performs a data analysis of the various experiments, identifies gaps in existing experimentation and proposes a comprehensive experimentation measurement reporting at the system, rock, brine and oil levels that leads to enhanced understanding of the underlying recovery mechanisms and their associated parameters. Secondly, a sustainable approach of implementing Machine Learning (ML) and Artificial Intelligence Tools (AIT) is proposed and implemented which aids in improving the screening of the value added from this DCW recovery. Two primary interaction mechanisms are identified as part of this research, gaps in current experimentation are identified with recommendations on what other parameters need to be measured and finally the accuracy of application of ML/AI tools is demonstrated. This work also provides for efficient and fast screening before application of more resource and cost intensive modeling of the subsurface earth system. Improved understanding, knowledge and screening enables making better decisions in implementation of DCW, which is a sustainable recovery option given the current state of affairs with zero carbon and net zero initiatives being on the rise. Full article

Recent research has highlighted wettability alteration as the main consequence of the different mechanisms involved in technologies such as adjusted brine composition water flooding (ABCW) and low-salinity water flooding (LSW). However, studies are still needed to give a phenomenological explanation, and the most influential components of the system (rock–oil–brine) must be clarified. This work focuses on determining the most relevant variables for the smart water effects to occur. Static (contact angles) and dynamic tests (coreflooding) were conducted. For the static tests, aged Berea slices, a specific crude oil (27° API, 10.5 cp at 60 °C), and mono and divalent inorganic salts (Na⁺, K⁺, Ca²⁺, and Mg²⁺/Cl⁻) were used in 3 different concentrations of 1000, 3000, and 5000 ppm (ionic strength variation between 0.015 and 0.06) to establish the wettability state by measuring the contact angles of the system. When salts containing chloride were evaluated, a decrease in oil wettability was observed at 5000 ppm. At 3000 and 1000 ppm, tendencies depended on the particular cation. Three brines were selected from the contact angle experiments to be used in coreflooding assays, considering a particular design to identify ion exchange from the rock–oil–brine system. The first assay was carried out in the absence of crude oil as a baseline to determine the ion exchange between the brine and the rock, and a second test considered crude oil to provide insight into ion exchange and its effect on displacement efficiency. Capillary electrophoresis was used in this research as a novel contribution to the systematic study of oil displacement tests, and it has proven to be a powerful tool for understanding the mechanisms involved. The results show that the variations in the concentrations detected in the displacement effluents were the product of the interactions between rock, oil, and brine since the concentrations measured in the absence of oil phase were comparable to those in the injection brine. Significant variations in the effluent ion concentrations were determined for the different brines used, and increases in the pressure differentials were observed for the KCl and CaCl₂ brines. These results suggest that the oil–brine ion exchange (salting in/out) represents a relevant mechanism to explain the observed displacement efficiencies and differential pressures. The ionic enrichment of the water phase due to the salting in/out effect needs to be better understood. Full article

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. Full article

Heavy-oil mobility in reservoir rocks can be improved, using nanotechnology, by reducing the viscosity of the oil and improving the rock wettability to a water-wet condition. Previous pilot studies in Colombian heavy oil fields reported that nanoparticles dispersed in an oleic carrier fluid (diesel) increased oil production rates between 120–150% higher than before the interventions. However, to optimally deploy a massive nanofluid intervention campaign in heavy oil fields, it is valuable to implement simulation tools that can help to understand the role of operational parameters, to design the operations and to monitor the performance. The simulator must account for nanoparticle transport, transfer, and retention dynamics, as well as their impact on viscosity reduction and wettability restoration. In this paper, we developed and solved, numerically, a 3D mathematical model describing the multiphase flow and interaction of the nanoparticles with oil, brine, and rock surface, leading to viscosity reduction and wettability restoration. The model is based on a multiphase pseudo-compositional formulation, coupled with mass balance equations, of nanoparticles dispersed in water, nanoparticles dispersed in oil, and nanoparticles retained on the rock surface. We simulated a pilot test study of a nanofluid stimulation done in a Colombian heavy oil field. The injection, soaking, and production stages were simulated using a 3D single-well formulation of the mathematical model. The comparison of simulation results with the pilot test results shows that the model reproduced the field observations before and after the stimulation. Simulations showed that viscosity reduction during the post-stimulation period is strongly related to the detachment rate of nanoparticles. Simulation indicates that the recovery mechanism of the nanofluid stimulation is initially governed by viscosity reduction and wettability alteration. At latter times, wettability alteration is the main recovery mechanism. The nanoparticles transferred to the residual water promote the wettability alteration to a water wet condition. The model can be used to design field deployments of nanofluid interventions in heavy oil reservoirs. Full article

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 (<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. Full article

An understanding of clay mineral surface chemistry is becoming critical as deeper levels of control of reservoir rock wettability via fluid–solid interactions are sought. Reservoir rock is composed of many minerals that contact the crude oil and control the wetting state of the rock. Clay minerals are one of the minerals present in reservoir rock, with a high surface area and cation exchange capacity. This is a first-of-its-kind study that presents zeta potential measurements and insights into the surface charge development process of clay minerals (chlorite, illite, kaolinite, and montmorillonite) in a native reservoir environment. Presented in this study as well is the effect of fluid salinity, composition, and oilfield operations on clay mineral surface charge development. Experimental results show that the surface charge of clay minerals is controlled by electrostatic and electrophilic interactions as well as the electrical double layer. Results from this study showed that clay minerals are negatively charged in formation brines as well as in deionized water, except in the case of chlorite, which is positively charged in formation water. In addition, a negative surface charge results from oilfield operations, except for operations at a high alkaline pH range of 10–13. Furthermore, a reduction in the concentrations of Na, Mg, Ca, and bicarbonate ions does not reverse the surface charge of the clay minerals; however, an increase in sulfate ion concentration does. Established in this study as well, is a good correlation between the zeta potential value of the clay minerals and contact angle, as an increase in fluid salinity results in a reduction of the negative charge magnitude and an increase in contact angle from 63 to 102 degree in the case of chlorite. Lastly, findings from this study provide vital information that would enhance the understanding of the role of clay minerals in the improvement of oil recovery. Full article

We present a systematic study of crude oil–brine–rock interactions in tight chalk cores at reservoir conditions. Flooding experiments are performed on outcrops (Stevns Klint) as well as on reservoir core plugs from Dan field, the Ekofisk and Tor formations. These studies are carried out in core plugs with reduced pore volumes, i.e., short core samples and aged with a dynamic ageing method. The method was evaluated by three different oil compositions. A series of synthetic multicomponent brines and designed fluid injection scenarios are investigated; injection flow rates are optimized to ensure that a capillary-dominant regime is maintained. Changes in brine compositions and fluid distribution in the core plugs are characterized using ion chromatography and X-ray computed tomography, respectively. First, we show that polar components in the oil phase play a major role in wettability alteration during ageing; this controls the oil production behavior. We also show that, compared to seawater, both formation water and ten-times-diluted seawater are better candidates for enhanced oil recovery in the Dan field. Finally, we show that the modified flow zone indicator, a measure of rock quality, is likely the main variable responsible for the higher oil recoveries observed in Tor core samples. Full article

Geological storage of CO₂ in saline aquifers and depleted oil and gas reservoirs can help mitigate CO₂ emissions. However, CO₂ leakage over a long storage period represents a potential concern. Therefore, it is critical to establish a good understanding of the interactions between CO₂–brine and cement–caprock/reservoir rock to ascertain the potential for CO₂ leakage. Accordingly, in this work, we prepared a unique set of composite samples to resemble the cement–reservoir rock interface. A series of experiments simulating deep wellbore environments were performed to investigate changes in chemical, physical, mechanical, and petrophysical properties of the composite samples. Here, we present the characterisation of composite core samples, including porosity, permeability, and mechanical properties, determined before and after long-term exposure to CO₂-rich brine. Some of the composite samples were further analysed by X-ray microcomputed tomography (X-ray µ-CT), X-ray diffraction (XRD), and scanning electron microscopy–energy-dispersive X-ray (SEM–EDX). Moreover, the variation of ions concentration in brine at different timescales was studied by performing inductively coupled plasma (ICP) analysis. Although no significant changes were observed in the porosity, permeability of the treated composite samples increased by an order of magnitude, due mainly to an increase in the permeability of the sandstone component of the composite samples, rather than the cement or the cement/sandstone interface. Mechanical properties, including Young’s modulus and Poisson’s ratio, were also reduced. Full article

The use of engineered water (EW) nanofluid flooding in carbonates is a new enhanced oil recovery (EOR) hybrid technique that has yet to be extensively investigated. In this research, we investigated the combined effects of EW and nanofluid flooding on oil-brine-rock interactions and recovery from carbonate reservoirs at different temperatures. EW was used as dispersant for SiO₂ nanoparticles (NPs), and a series of characterisation experiments were performed to determine the optimum formulations of EW and NP for injection into the porous media. The EW reduced the contact angle and changed the rock wettability from the oil-wet condition to an intermediate state at ambient temperature. However, in the presence of NPs, the contact angle was reduced further, to very low values. When the effects of temperature were considered, the wettability changed more rapidly from a hydrophobic state to a hydrophilic one. Oil displacement was studied by injection of the optimised EW, followed by an EW-nanofluid mixture. An additional recovery of 20% of the original oil in place was achieved. The temperature effects mean that these mechanisms are catalytic, and the process involves the initiation and activation of multiple mechanisms that are not activated at lower temperatures and in each standalone technique. Full article