Reservoir Brine Research Articles

Improved Stereophotogrammetric and Multi-View Shape-from-Shading DTMs of Occator Crater and Its Interior Cryovolcanism-Related Bright Spots

Over the course of NASA’s Dawn Discovery mission, the onboard framing camera mapped Ceres across a wide wavelength spectrum at varying polar science orbits and altitudes. With increasing resolution, the uniqueness of the 92 km wide, young Occator crater became evident. Its central cryovolcanic dome, Cerealia Tholus, and especially the associated bright carbonate and ammonium chloride deposits—named Cerealia Facula and the thinner, more dispersed Vinalia Faculae—are the surface expressions of a deep brine reservoir beneath Occator. Understandably, this made this crater the target for future sample return mission studies. The planning and preparation for this kind of mission require the characterization of potential landing sites based on the most accurate topography and orthorectified image data. In this work, we demonstrate the capabilities of the freely available and open-source USGS Integrated Software for Imagers and Spectrometers (ISIS 3) and Ames Stereo Pipeline (ASP 2.7) in creating high-quality image data products as well as stereophotogrammetric (SPG) and multi-view shape-from-shading (SfS) digital terrain models (DTMs) of the aforementioned spectroscopically challenging features. The main data products of our work are four new DTMs, including one SPG and one SfS DTM based on High-Altitude Mapping Orbit (HAMO) (CSH/CXJ) and one SPG and one SfS DTM based on Low-Altitude Mapping Orbit (LAMO) (CSL/CXL), along with selected Extended Mission Orbit 7 (XMO7) framing camera (FC) data. The SPG and SfS DTMs were calculated to a GSD of 1 and 0.5 px, corresponding to 136 m (HAMO SPG), 68 m (HAMO SfS), 34 m (LAMO SPG), and 17 m (LAMO SfS). Finally, we show that the SPG and SfS approaches we used yield consistent results even in the presence of high albedo differences and highlight how our new DTMs differ from those previously created and published by the German Aerospace Center (DLR) and the Jet Propulsion Laboratory (JPL).

Critical Geochemical and Microbial Reactions in Underground Hydrogen Storage: Quantifying Hydrogen Loss and Evaluating CO2 as Cushion Gas

Hydrogen is a pivotal energy carrier for achieving sustainability and stability, but safe and efficient geological underground hydrogen storage (UHS) is critical for its large-scale application. This study investigates the impacts of geochemical and biochemical reactions on UHS, addressing challenges that threaten storage efficiency and safety. Geochemical reactions in saline aquifers, particularly the generation of hydrogen sulfide (H2S), were analyzed using advanced compositional and geochemical modeling calibrated with experimental kinetic data. The results indicate that geochemical reactions have a minimal effect on hydrogen consumption. However, by year 10 of storage operations, H2S levels could reach 12–13 ppm, necessitating desulfurization to maintain storage performance and safety. The study also examines the methanogenesis reaction, where microorganisms consume hydrogen and carbon dioxide to produce methane. Numerical simulations reveal that microbial activity under suitable conditions can reduce in situ hydrogen volume by up to 50%, presenting a critical hurdle to UHS feasibility. These findings highlight the necessity of conducting microbial analyses of reservoir brines during the screening phase to mitigate hydrogen losses. The novelty of this work lies in its comprehensive field-scale analysis of impurity-induced geochemical and microbial reactions and their implications for underground hydrogen storage. By integrating kinetic parameters derived from experimental data with advanced computational modeling, this study uncovers the mechanisms driving these reactions and highlights their impact on storage efficiency, and safety. By offering a detailed field-scale perspective, the findings provide a pivotal framework for advancing future hydrogen storage projects and ensuring their practical viability.

Boron to salinity ratios in the Fram Strait entering the Central Arctic: The role of sea ice formation and future predictions

The Arctic Ocean's sea ice loss dynamically impacts carbon uptake potential, as assessed through measured carbonate parameters, such as total alkalinity. In the open ocean, boron (B) is the third largest contributor to alkalinity via borate and is usually accounted for through the conservative boron to salinity ratio (B/S), and not directly measured. Here, we present findings on non-conservative boron dynamics, that results in significant B/S deviations, observed in ice melt zone waters, snow, slush, brine, and annual sea ice (n = 169) in the Fram Strait entering the Central Arctic. These samples were collected during the onset of the melt season on the 2023 ARTofMELT expedition, covering a wide practical salinity range (2–59). Barring snow, the average B/S ratio across the study was 0.1321 ± 0.0032 mg kg−1 ‰−1, similar to the mean B/S ratio measured amongst several polar water masses near Iceland, as well as the accepted B/S for other ocean regions. Results indicate minor deviations from accepted B/S ratios (indicating conservative behavior) across the sample practical salinity range and reflect an uncertainty in the borate contribution to total alkalinity of less than 2.9 μmol kg−1 at in-situ temperatures. B fractionation appears to occur during sea ice formation, causing greater B in the sea ice reservoir whereas brine, slush, lead, and under-ice water reservoirs are depleted in B. As such, under-ice and lead, brine, and slush samples all had measured B/S ratios (0.1305 ± 0.0011, 0.1305 ± 0.0018, and 0.1304 ± 0.0017 mg kg−1 ‰−1, respectively) lower than the established ratio whereas the average sea ice B/S ratio (0.1331 ± 0.0035 mg kg−1 ‰−1) was closest to accepted values (0.1336 ± 0.0005 mg kg−1 ‰−1). Arctic open ocean samples also had a lower B/S ratio (0.1304 ± 0.0014 mg kg−1 ‰−1). Our findings, together with a previous Arctic B ice study, suggest that B (probably in the form of B(OH)4−) is incorporated into authigenic CaCO3 minerals, replacing CO32− within the mineral lattice during sea ice formation. This process consequentially lowers the B/S ratio in the open Arctic Ocean, compared to the established global ocean ratio. Nevertheless, the incorporation of B into the sea ice reservoir does not fully account for the deficit of B in the Arctic Ocean samples, suggesting further accounting of B Arctic pathways is necessary. In future climate scenarios involving increased sea ice melt, the transition from multiyear to annual sea ice, permafrost thaw, and increased riverine discharge, the behavior of B in the Arctic Ocean is expected to become more dynamic.

Inheritance recharge of subsurface brine constrains on formation of K-bearing sand-gravel brine in the alluvial fan zone of mountain-basin system on the Qinghai-Tibetan Plateau

The deep brines enriched in potassium (K), lithium (Li), boron (B) resource elements in sedimentary basins are valuable potential mineral resources. There is a widely accepted consensus that evaporite and brine resources were formed in terminal salt lakes, however, newly discovered sand-gravel brine (SGB) occurred in the piedmont alluvial fan zone on the northern Qinghai-Tibetan Plateau (QTP). Currently, there is a key scientific issue on where does the solute of SGB in the alluvial fan zone come from? The existing understanding is that the solute of high Na+, Cl− originates from halite dissolution by meteoric water, but lack of isotope geochemical linkage between brine and evaporite. The Mahai Basin (MHB) on the northern QTP is a natural experimental site for the study on the above unsolved problems, due to harboring similar brine reservoir, small geographical area, thin evaporite layers and various waters in this basin. This study presents detailed analysis of H-O-Cl-Li isotopic compositions and hydrogeochemical parameters for intercrystalline brine, SGB and halite from drilling cores in the MHB. The results reveal several key findings: (1) the SGB in the piedmont alluvial fan zone of Altyn Tagh and Saishiteng Mountains presents similar geochemical characteristics of low TDS, high Na+, Cl− and relatively high K+ contents (1.12–3.65 g/L in MHB), which established new occurrence model of brine resource in the ‘Fan-Lake’ system. (2) The δD (−56.90 ‰∼−17.60 ‰) and δ18O (−5.70 ‰∼6.00 ‰) values of SGB in the MHB are higher, the isotopic disparity exists in these two mountain-fan-lake systems, but they are meteoric origin and accord with their respective hydrologic circulation process. (3) The CNa/CCl molar ratio (∼0.80), δ37Cl (−0.26 ‰∼+0.25 ‰) and δ7Li values (+33.84 ‰∼+43.82 ‰) of SGB are comparable with those of intercrystalline brine in the MHB, indicating that inheritance recharge of salt lake brine for the formation of SGB in this basin. (4) The metallogenic model of SGB in the MHB is multi-condition constraints (northward migration of depocenter, hydrological lateral recharge of river water along the alluvial fault zone and strata subsidence along with the mountain uplift), which develops the topographic difference between brine aquifers of salt lake and alluvial fan zone resulting into subsurface brines recharge for the alluvial-pluvial fan reservoir.

HPAM-Cr (III) Gel Syneresis in Bulk Volume

This paper explores the crucial factors influencing the stability of polymer gels utilized in oil well treatments, with a focus on the effects of polymer mixing time and concentrations of polymer and crosslinker. Operating within a practical constraint of a 30-minute mixing time in surface facilities, our findings reveal that incomplete polymer dissolution leads to gel segregation and substantial water release over extended aging at 50 ºC. Notably, a reduction in the crosslinker/ polymer ratio, achieved by lowering crosslinker concentration or increasing polymer concentration, proves effective in mitigating water release to as low as 0‒1% over 90‒185 h of aging. Furthermore, gels prepared in sea and reservoir brines exhibit superior stability compared to those in distilled water, suggesting that ion presence in brines counteracts the repulsion between charged polymer chains observed in distilled water. This study provides valuable insights for optimizing polymer gel formulations under time constraints.

Evaluating CO 2 retention risk of geological sequestration sites: physical, time-scale, and site style considerations

With some exceptions, such as fluid phase, pressure evolution, and reservoir geometry, evaluation of CO 2 retention for geological sequestration sites primarily involves well-established seal and trap concepts and methods developed by the petroleum industry. Inputs to a CO 2 retention evaluation (e.g. bed seal capacity analysis) include CO 2 phase, CO 2 and brine density, reservoir pressure and temperature, rock properties, and stress state. The inputs are used to perform capillary and mechanical seal analyses similar to the petroleum industry, but unlike hydrocarbons, CO 2 retention also occurs within the reservoir pore volume by capillary and solubility trapping, adding additional requirement for analyses using reservoir engineering concepts and methodology. Reservoir geometry types for CO 2 storage include conventional traps (depleted hydrocarbon fields, brine-filled traps) and brine-filled reservoirs that lack a conventional trap geometry (e.g. a monocline). Each geometry style and project phase (injection, near-term post-injection, long-term static) requires different retention considerations, for example the CO 2 plume extent and height. Based on a retention evaluation, retention risk and uncertainty may be articulated using a qualitative risk matrix that facilitates early screening, identification of data needs, possible mitigating strategies, and comparisons across a portfolio of potential sites. Thematic collection: This article is part of the Geoscience workflows for CO 2 storage collection available at: https://www.lyellcollection.org/topic/collections/geoscience-workflows-for-CO2-storage

Deep basin conductor characterization using machine learning-assisted magnetotelluric Bayesian inversion in the SW Barents Sea

SUMMARY In this paper, we use a new workflow to substantiate the characterization of a prominent, deep sediment conductor in the hyperextended Bjørnøya Basin (SW Barents Sea) previously identified in smooth resistivity models from 3-D deterministic inversion of magnetotelluric data. In low-dimensionality environments like layered sedimentary basin, 1-D Bayesian inversion can be advantageous for a thorough exploration of the solution space, but the violation of the 1-D assumption has to be efficiently handled. The primary geological objectives of this work is therefore preceded by a secondary task: the application of a new machine learning approach for handling the 1-D violation assumption for 21 MT field stations in the Barents Sea. We find that a decision tree can adequately learn the relationship between MT dimensionality parameters and the 1-D–3-D residual response for a training set of synthetic models, mimicking typical resistivity structures of the SW Barents Sea. The machine learning model is then used to predict the dimensionality compensation error for MT signal periods ranging of 1–3000 s for 21 receivers located over the Bjørnøya Basin and Veslemøy High. After running 1-D Bayesian inversion, we generated a posterior resistivity distribution for an ensemble of 6000 1-D models fitting the compensated MT data for each 21 field stations. The proportion of 1-D models showing ρ < 1 Ω·m is consistently beyond 80 per cent and systemically reaches a maximum of 100 per cent in the Early Aptian–Albian interval in the Bjørnøya Basin. In hyperextended basins of the SW Barents Sea, the dimensionality compensation workflow has permitted to refine the characterization of the deep basin conductor by leveraging the increased vertical resolution and optimal used of MT data. In comparison, the smooth 3-D deterministic models only poorly constrained depth and lateral extent of the basin anomaly. The highest probability of finding ρ < 1 Ω·m is robustly assigned to the syn-tectonic Early Aptian–Albian marine shales, now buried at 6–8 km depth. Based on a theoretical two phase fluid-rock model, we show that the pore fluid of these marine shales must have a higher salinity than seawater to explain the anomaly ρ < 1 Ω·m. Therefore, the primary pore fluid underwent mixing with a secondary brine during rifting. Using analogue rift systems in palaeomargins, we argue that two possible secondary brine reservoir may contribute to deep saline fluid circulation in the hyperextended basin: (1) Permian salt-derived fluid and, (2) mantle-reacted fluid from serpentinization.

Environmental risk assessment of underground concentrated brine reservoir with solute transport model: A case study of a coal mine in Northwest China

Underground reservoirs have emerged as a promising technology for storing and reusing saline wastewater from coal mines. However, the high salinity and potential leakage risks pose environmental threats needing assessment. This study developed an integrated solute transport and relative risk modeling framework to evaluate the environmental risks of an underground concentrated brine reservoir (UCBR) in Northwest China. The solute transport model simulated subsurface brine migration under long-term penetration, sudden leakage, and complete leakage scenarios, parameterized by field data. The relative risk model integrated source, receptor, and exposure analyses to quantify normalized risk levels. Results revealed that risks incrementally rose over longer storage durations, with 70 years posing high risk under 10 m hydraulic gradients in the long-term scenario. The risk of sudden leakage is controllable within 30 days but dramatically elevated by 60 days. Complete leakage was predicted to affect a stable 3 km2 zone. The integrated modeling provides an improved methodology for assessing UCBR risks and highlights the critical influence of bottom barrier permeability, groundwater gradients, and storage time. Targeted strategies are proposed, including reinforcing bottom barriers, managing hydraulic gradients, controlling storage durations, implementing early warning systems, and contingency planning to promote sustainable mining water management.

Prediction of Lithium Oilfield Brines Based on Seismic Data: A Case Study from L Area, Northeastern Sichuan Basin, China

Lithium is an important mineral resource and a critical element in the production of lithium batteries, which are currently in high demand. Oilfield brine has significant value as a raw material for lithium extraction. However, it is often considered a byproduct of oil and gas production and is either abandoned or reinjected underground. Exploration and development of oilfield brines can enhance the economic benefits of oilfields and avoid wasting resources. Current methods for predicting brine distribution rely on geological genetic analysis, which results in low accuracy and reliability. To address this issue, we propose a workflow for lithium brine prediction that uses seismic and logging data. We introduced waveform clustering control and used the mapping relationship between seismic waveforms and well-logging curves to predict high-quality reservoirs based on the electrical and physical properties of lithium brine reservoirs. In this workflow, the seismic waveforms were first clustered using singular value decomposition. The sample sets of well-logging properties were established for the target location. The target properties were divided into high- and low-frequency components and predicted separately. The predicted results of the high-quality reservoirs in the study area were verified using elemental content test results to demonstrate the effectiveness of the method. Our study indicates that well-logging property prediction constrained by waveform clustering can predict lithium brines in a carbonate reservoir.

Brine Drying and Salt Precipitation in Porous Media: A Microfluidics Study

AbstractDrying and salt precipitation in porous media impact various engineering disciplines, including carbon geological storage in brine reservoirs, with considerable hydraulic and mechanical effects. However, understanding the underlying mechanisms and controlling factors is limited due to the lack of pore‐scale observation and quantitative analysis. We design radial flow microfluidic chips with varying pore heterogeneity and wettability and quantify the pore‐scale dynamics of brine drying and salt precipitation using time‐lapse images and image processing techniques. The gas injection process determines the distribution of residual (drying) brine and is influenced by pore heterogeneity. Higher concentrations of residual brine are observed near the injection well in more heterogeneous porous media. Capillary backflow replenishes evaporative losses near the well during drying in hydrophilic chips. Brine clusters induced by gas injection connect through brine films and reconnect by capillary backflow. Two types of pore habits of salt precipitation are identified: bulk salt within brine clusters and aggregated salt at the air‐brine interface. Salt precipitation, particularly near the injection well, significantly reduces injectivity, with less impact observed in the porous media with uniform pore structure and hydrophobic surfaces.

Scope of Implementation of Low Salinity Nanofluid to Improve Oil Recovery in a Part of the Hapjan Oil Field of Upper Assam Basin

The application of nanoparticles in the field of Enhanced Oil Recovery (EOR) has been an emerging technology in recent years. Earlier studies have shown that the nanofluids containing nanoparticles (NPs) of average size (<100 nm) can enhance the oil recovery through wettability alteration of rock, reduction of mobility ratio, reduction of oil-aqueous solution interfacial tension (IFT), reduction of sand production and improvement of sweep efficiency. Low Salinity Waterflooding (LSW) has been utilized as a promising EOR method in the last two decades. Recent studies have found that nanoparticle-assisted LSW embraces both nanoparticles and ions as EOR agents in the injection brine. This study investigates the scope of implementation of the low salinity nanofluid EOR using silica nanoparticles to improve oil recovery in the Tipam Reservoir Sandstone of the Hapjan Oil Field of Upper Assam Basin, India. The analysis of the reservoir brine, reservoir rock and crude oil shows the presence of divalent cations (Ca2+ and Mg2+), clay minerals (Illite and Smectite) and polar compounds (Asphaltene and Resin) respectively. The presence of the divalent cations, clay minerals and polar compounds in the Crude Oil/Brine/Rock system of a sandstone reservoir is the prerequisite for implementing low salinity nanofluid EOR. The study shows that the low salinity nanofluids can shift the wettability of the rock to a more water-wet state. It is also observed that the silica nanoparticles can increase the nanofluid viscosity and reduce the oil-nanofluid IFT, which can improve the recovery of oil. The experimental results show that the study area has great potential for the low salinity silica nanofluid EOR to improve oil recovery.

A comprehensive review of viscoelastic polymer flooding in sandstone and carbonate rocks

Polymer flooding is a proven chemical Enhanced Oil Recovery (cEOR) method that boosts oil production beyond waterflooding. Thorough theoretical and practical knowledge has been obtained for this technique through numerous experimental, simulation, and field works. According to the conventional belief, this technique improves macroscopic sweep efficiency due to high polymer viscosity by producing moveable oil that remains unswept after secondary recovery. However, recent studies show that in addition to viscosity, polymer viscoelasticity can be effectively utilized to increase oil recovery by mobilizing residual oil and improving microscopic displacement efficiency in addition to macroscopic sweep efficiency. The polymer flooding is frequently implemented in sandstones with limited application in carbonates. This limitation is associated with extreme reservoir conditions, such as high concentrations of monovalent and divalent ions in the formation brine and ultimate reservoir temperatures. Other complications include the high heterogeneity of tight carbonates and their mixed-to-oil wettability. To overcome the challenges related to severe reservoir conditions, novel polymers have been introduced. These new polymers have unique monomers protecting them from chemical and thermal degradations. Monomers, such as NVP (N-vinylpyrrolidone) and ATBS (2-acrylamido-2-methylpropane sulfonic acid), enhance the chemical resistance of polymers against hydrolysis, mitigating the risk of viscosity reduction or precipitation in challenging reservoir conditions. However, the viscoelasticity of these novel polymers and their corresponding impact on microscopic displacement efficiency are not well established and require further investigation in this area. In this study, we comprehensively review recent works on viscoelastic polymer flow under various reservoir conditions, including carbonates and sandstones. In addition, the paper defines various mechanisms underlying incremental oil recovery by viscoelastic polymers and extensively describes the means of controlling and improving their viscoelasticity. Furthermore, the polymer screening studies for harsh reservoir conditions are also included. Finally, the impact of viscoelastic synthetic polymers on oil mobilization, the difficulties faced during this cEOR process, and the list of field applications in carbonates and sandstones can also be found in our work. This paper may serve as a guide for commencing or performing laboratory- and field-scale projects related to viscoelastic polymer flooding.

Microfluidics for Carbonate Rock Improved Oil Recovery: Some Lessons from Fabrication, Operation, and Image Analysis

Summary After the successful implementation of lab-on-a-chip technology in chemical and biomedical applications, the field of petroleum engineering is currently developing microfluidics as a platform to complement traditional coreflooding experiments. Potentially, microfluidics can offer a fast, efficient, low-footprint, and low-cost method to screen many variables such as injection brine composition, reservoir temperature, and aging history for their effect on crude oil (CRO) release, calcite dissolution, and CO2 storage at the pore scale. Generally, visualization of the fluid displacements is possible, offering valuable mechanistic information. Besides the well-known glass- and silicon-based chips, microfluidic devices mimicking carbonate rock reservoirs are currently being developed as well. In this paper, we discuss different fabrication approaches for carbonate micromodels and their associated applications. One approach in which a glass micromodel is partially functionalized with calcite nanoparticles is discussed in more detail. Both the published works from several research groups and new experimental data from the authors are used to highlight the current capabilities, limitations, and possible extensions of microfluidics for studying carbonate rock systems. The presented insights and reflections should be very helpful in guiding the future designs of microfluidics and subsequent research studies.

First assessment of hydrogen/brine/Saudi basalt wettability: implications for hydrogen geological storage

Introduction: Underground hydrogen (H2) storage is a prominent technique to enable a large-scale H2-based economy as part of the global energy mix for net-zero carbon emission. Recently, basalts have gained interest as potential caprocks for subsurface H2 storage due to their low permeability, vast extension, and potential volumetric capacity induced by structural entrapment of the buoyant H2. Wettability represents a fundamental parameter which controls the capillary-entrapment of stored gases in porous media.Methods: The present study evaluates the wettability of basalt/H2/brine system of two basalt samples from Harrat Uwayrid, a Cenozoic volcanic field, in Saudi Arabia. The H2/basalt contact angle was measured using a relevant reservoir brine (10% NaCl) under storage conditions of 323K temperature and pressure ranges from 3 to 28 MPa using the modified sessile drop method. The surface roughness of the basaltic rocks was determined to ensure accurate results.Results: The investigated Saudi basalt samples are water-wet, thereby they did not achieve a 100% hydrogen wetting phase even at 28 MPa pressure. The measured contact angles slightly decrease as pressure increases, thereby pressure did not significantly influences the height of the H2 column.Discussion: We interpret this trend to the slight increase in H2 density with increasing pressure as well as to the olivine-rich mineralogical composition of the Saudi basalt. Thus, from the wettability aspects, Saudi basalt has the potential to store a large volume of H2 (>1,400 m height) and maintain its excellent storage capacity even in deep, high-pressure regimes. This study demonstrates that the basalt rock texture (pore throat radii) and mineralogy control their capacity for subsurface H2 storage.

Solubility and interfacial tension models for CO2–brine systems under CO2 geological storage conditions

Thermodynamic properties of the CO2–brine pseudo-binary system are essential for the design of geological carbon storage (GCS) projects, especially those utilizing saline aquifers. The gas–liquid–solid interactions manifest in the interfacial tensions (IFTs) and contact angle determine the injectability, sealing capacity, and storage security of the GCS process. Dissolution of CO2 in the reservoir brine occurs throughout the entire GCS process, leading to enhanced storage capacity but also to acidification of the brine, possibly leading to reservoir or seal damage. Two of the most important thermodynamic properties of the fluids are the mutual solubility and the IFT of the CO2–brine pseudo-binary system. In this work, we report a new correlative model for the IFT between CO2- and water-rich phases over wide ranges of temperature (273 to 473 K) and pressure (up to 100 MPa). The model is parameterized for brines comprising any combinations of sodium, potassium, calcium and magnesium cations with chloride, sulphate and bicarbonate anions up to a total molality of at least 5 mol·kg−1. The independent variables in this new model are reduced temperature, ion molalities and the mole fraction of CO2 dissolved in the aqueous phase. The latter is related to temperature, pressure and ion molalities by an improved model for the mutual solubility. More than 2000 experimental data points were used in the development of the two models. For the IFT of the CO2-H2O binary system, the overall root-mean-square deviation (RMSD) is 0.65mN·m−1 while the absolute average relative deviation (AARD) is 1.8%. In the case of mutual solubility, the RMSD of CO2 mole fraction in the aqueous phase is 0.0003 and the AARD is 5.5% while, in the non-aqueous phase, the RMSD of H2O mole fraction is 0.0035 and the corresponding AARD is 8.7%. Similar results are found for the CO2-brine systems.

Role of Reservoir Brine and Rock in Modulating Asphaltene Stability: Insights from Experimental Analysis

Summary The stability of asphaltenes in crude oil is influenced by various factors, including interactions with reservoir components such as brine and rock formations. While previous research has focused on pressure and temperature effects, a comprehensive understanding of the combined impact of brine and reservoir rock on asphaltene stability is lacking. This study investigates the individual and combined influences of brine and rock formations on asphaltene stability. First, 11 crude oil samples from diverse locations were characterized using API gravity, viscosity, and saturates, aromatics, resins, and asphaltenes (SARA) fraction analysis. The elemental composition of the crude oils, including carbon, hydrogen, nitrogen, and various metals, was determined. The surface properties of asphaltenes were analyzed using scanning electron microscopy coupled with energy-dispersive X-ray spectroscopy (SEM-EDS). The interaction between asphaltenes and deionized water was examined through zeta potential, particle size, conductivity, and pH measurements. The behavior of asphaltenes in an 8,000 ppm NaCl solution was also investigated. The SEM analysis revealed the presence of inorganic content on the surfaces of asphaltenes, indicating interactions between asphaltenes and reservoir rock. A strong correlation between the zeta potential and sulfur content of asphaltenes was observed, highlighting the influence of sulfur compounds on surface charge and stability in heavy crudes. Additionally, the correlation between total dissolved solids (TDS) content and alkaline Earth metals and alkali metals in asphaltenes confirmed interactions between asphaltenes and reservoir brine. This interaction is likely influenced by the composition and properties of both the brine and reservoir rock. The presence of electrical charges on the asphaltene surfaces, as determined by zeta potential measurements, further supports the role of electrostatic interactions in asphaltene stability. The low precipitation tendency observed for most asphaltene samples, coupled with the abundance of negatively charged particles, underscores the importance of electrical charges in controlling stability. This study provides novel insights into asphaltene stability, highlighting the significance of surface charge and elemental composition. The results demonstrate the substantial impact of both reservoir brine and rock formations on asphaltene stability in crude oil. Further research is needed to unravel the complex mechanisms underlying these interactions and their implications in diverse reservoir environments.

CO2 Dissolution in the reservoir brine: An experimental and simulation-based approach

This study benefits from carbon dioxide gas (CO2) dissolution experiments to mimic CO2 dissolution behavior under reservoir conditions. A unique experimental setup, consisting of a batch reactor, gas flow meter, and a sampling separator, was used to measure CO2 dissolution in the geothermal brine at various temperatures (20 °C to 142 °C) and pressures (1 barg to 13 barg). The CO2 was measured using a gas flowmeter and alkalinity tests. It was observed that the experiments’ results matched with a PHREEQC model and empirical correlations available in the literature with R-square values more than 0.86. Water salinity and gas impurity effects on CO2 dissolution were investigated using a calibrated PHREEQC model. CO2 dissolution enhanced mineral solubility such as gypsum, calcium, dolomite, and halite. The study also investigated CO2 dissolution kinetics using batch experiments. The pressure behavior of the gas-brine mixture showed the importance of complete mixing to reach the maximum gas dissolution in the brine. The mixing process showed that at least 2000 s of mixing is required to achieve the maximum dissolving capacity of the geothermal brine at the experiment conditions. The novelty of the study is using real reservoir gas and reservoir brine for CO2 dissolution experiments in a unique experimental setup. Therefore, it will provide insight for CO2 sequestration in geothermal reservoirs.

Seismic characteristics and AVO response for non-uniform Miocene reservoirs in offshore eastern Mediterranean region, Egypt

The Eastern Mediterranean region, extending from the Offshore Nile Delta Cone of Egypt to the Levant Basin, is a confirmed hydrocarbon-rich territory with several giant gas discoveries. Numerous gas fields have been discovered in the Miocene reservoirs within the Nile Delta Cone, and the Levant Basin. The Miocene sedimentary sequences in this region are extremely heterogeneous, consisting mainly of turbiditic slope deposits, channels, and basin floor fans that were capped by evaporites formed during the Messinian Salinity Crisis. As a result, the seismic characteristics and interpreted properties of this heterogeneous section are ambiguous. The study area is located in the Offshore North Sinai Basin, where a thick Early Miocene section was deposited midway between the Nile Delta province, which includes the El-Fayrouz discovery, and the Levant Basin, which includes Tamar, Tanin, and several other discoveries. This study uses quantitative seismic interpretations methods, such as amplitude variations with offset and fluid replacement modeling, to assess the seismic acoustic impedance trend with depth. Also, determine the seismic amplitude response for the brine and gas sands reservoir of the Early and Late Miocene section to link the unexplored study area within the North Sinai Offshore Basin with the explored Nile Delta and Levant Basins. In addition to evaluate direct hydrocarbon indicator (DHI) of the dimming seismic amplitude that is compatible with the structure’s last closed contour of the Syrian Arc anticline of the Early Miocene reservoirs (EMT-1 prospect). Different vintages of 2D and 3D seismic data, six wells, and various published data were used in this study. The quantitative interpretation shows the pitfalls of the acoustic impedance trend and seismic response dependency on depth for gas and brine sand, which led to the drilling of the EMT-1 dry well. Also, the fluid replacement, P-wave velocity (Vp), and density (ρ) modeling confirmed that the seismic dimming amplitude was due to a seismic processing artifact, which was corrected by readjusting the overburden Messinian salt processing velocity model. This research concludes that the seismic quantitative interpretations are successfully used to assess the acoustic impedance versus depth and understand DHI pitfalls, as well as the processing workflow that could enhance the seismic image.

Viscosity behavior for zirconia and γ-alumina nanoparticles in different electrolytic solutions: An experimental investigation

Viscosity modification of injected fluids is a vital mechanism for successful oil recovery from an oil reservoir. Various studies have demonstrated that nanoparticles (NPs) possess the tendency to alter the wettability of reservoir rocks, reduce the interfacial tension between injected fluids and crude oil, and modify the viscosity of injected fluids. Zirconia (ZrO2) and γ-alumina (γ-Al2O3) NPs have demonstrated huge prospects for enhanced oil recovery (EOR) in various studies. Recently, experimental investigations have attributed the viscosity behavior of silica nanofluids to the interaction between the ions of the silica NPs and electrolytes at the electrical double layer. Therefore, this study investigates the viscosity behavior of ZrO2 and γ-Al2O3 NPs with their increasing concentrations in different aqueous solutions present in reservoir brine by employing techniques such as dynamic light scattering and transmission electron microscopy in addition to viscosity and pH measurements at ambient conditions of approximately 25℃ and 1 atm. The viscosity behavior of spherical particles in suspensions is well suited for the viscosity profile of the nanofluids with increasing concentrations of ZrO2 and γ-Al2O3 NPs. The viscosity of the ZrO2 and γ-Al2O3 nanofluids containing the chloride salts increases in the order of Ca2+ > Na+ > K+ while those containing the sulfate salts increase in the order Mg2+ > Na+ > K+. Comparatively, the model proposed by Williams et al. predicts the viscosities of the electrolyte-based zirconia and γ-Al2O3 nanofluids with percentage absolute average deviation (%AAD) of 2.07 and 2.52 %, respectively, whereas those by Einstein’s model records %AAD of 3.15 and 3.68 %, respectively. The findings from this study provide experimental data and illuminate the understanding of the viscosity behavior of the nanofluids containing electrolytic ions and set the stage for further investigations, which are relevant for EOR purposes.

Evaluating the hydrogen storage potential of shut down oil and gas fields along the Norwegian continental shelf

The underground hydrogen storage (UHS) capacities of shut down oil and gas (O&G) fields along the Norwegian continental shelf (NCS) are evaluated based on the publicly available geological and hydrocarbon production data. Thermodynamic equilibrium and geochemical models are used to describe contamination of hydrogen, loss of hydrogen and changes in the mineralogy. The contamination spectrum of black oil fields and retrograde gas fields are remarkably similar. Geochemical models suggest limited reactive mineral phases and meter-scale hydrogen diffusion into the caprock. However, geochemical reactions between residual oil, reservoir brine, host rock and hydrogen are not yet studied in detail. For 23 shut down O&G fields, a theoretical maximum UHS capacity of ca. 642 TWh is estimated. We conclude with Frigg, Nordost Frigg, and Odin as the best-suited shut down fields for UHS, having a maximum UHS capacity of ca. 414 TWh. The estimates require verification by site-specific dynamic reservoir models.