Search Results (161)

Counter-current, spontaneous imbibition of brine into oil-saturated rocks is a critical process for recovery of bypassed oil in carbonate reservoirs. However, the classic Amott-cell test introduces experimental artifacts that distort the true dynamics of oil recovery, complicating the interpretation and modeling of recovery histories. In this study, we applied a modified Amott procedure to eliminate these artifacts, producing smooth and reproducible recovery histories for both water-wet and mixed-wet carbonate core plugs saturated with brine and oil. By applying Generalized Extreme Value (GEV) statistics, we modeled cumulative oil production and showed that a GEV model is able to capture the essentially non-equilibrium nature of spontaneous imbibition. Our results demonstrate that water-wet systems exhibit faster recovery rates and shorter induction times due to favorable capillary forces, while mixed-wet samples have slower dynamics and longer induction times, reflecting the influence of wettability alterations. We demonstrate that the GEV fitting parameters systematically correlate with key rock–fluid properties, such as wettability, oil viscosity, and pore network characteristics, offering a semi-quantitative approach to analyze recovery behavior. This study demonstrates the potential of a GEV-based statistical model to deepen understanding of the spontaneous imbibition mechanisms and to enhance predictive capabilities for oil production dynamics. Full article

Oil recovery from low-permeability (‘tight’) oil reservoirs remains low despite the application of modern drilling and completions technologies, which has increased interest in trialing enhanced oil recovery (EOR) schemes. Cyclic gas injection (Huff-n-Puff, HNP) is a promising approach to EOR for these reservoirs. However, the underlying mechanisms of EOR using the HNP scheme in tight reservoirs are not yet fully understood. This laboratory study investigates the performance of lean gas (80%C₁ + 20%C₂; approximating produced gas compositions from the field) HNP using low-permeability core plug samples from the Montney Formation of Canada. An objective of the study was to evaluate the effects of induced fractures, and brine saturation and distribution, on the efficiency of lean gas HNP performance. Both intact and artificially fractured core plugs were studied. The introduction of fractures into the low-permeability core plugs improved recovery factors by 17.5–18.5%. However, the presence of brine limited oil production from both intact and fractured core plugs. Notably, when brine was concentrated along the fracture surfaces, the recovery factor dropped significantly, down to just 1.2% of original oil in place (OOIP). This reduction is primarily attributed to the low solubility of methane and ethane (C₁ + C₂) in brine, which hinders the injectant’s ability to diffuse into the core matrix and mobilize oil. The findings of this study will be of interest to operators evaluating the potential of cyclic gas injection in low-permeability reservoirs. Full article

This study presents both laboratory measurements and numerical modeling of wettability alterations following carbon dioxide (CO₂) injection in limestone carbonate reservoirs. Both synthetic and crude oil systems were evaluated using a Drop Shape Analyzer (DSA-100) to quantitatively measure the contact angle and interfacial tension (IFT) on limestone core samples under ambient and reservoir conditions. The results demonstrated that carbonated brine significantly reduced the IFT (2.0–4.1 dynes/cm) and contact angle (11.9–16.0°), indicating a shift toward more water-wet conditions, compared with the modest reductions in contact angle achieved with standard brine (1.6–6.7°). Synthetic fluid systems containing naphthenic acid initially exhibited stronger oil-wet behavior but also experienced wettability alterations when exposed to CO₂. A previously developed compositional reservoir simulation model, which was based on assumed relative permeability endpoints, was revised to incorporate the experimental findings of this study as a supporting tool. Incorporating the experimental wettability alteration effect of CO₂ in the numerical model by a 5.2% reduction in the residual oil saturation (the relative permeability endpoint) caused 2% increase in the oil recovery factor and 12% improvement in the CO₂ utilization efficiency (9780 standard cubic feet per stock tank barrel (SCF/STB) vs. 8620 SCF/STB). Overall, this work provides critical laboratory validation and supports by numerical simulation that CO₂-induced wettability alteration is a key mechanism underpinning CO₂-based enhanced oil recovery (EOR) and carbon capture, utilization, and storage (CCUS) deployment in limestone carbonate formations. Full article

The rise in atmospheric CO₂ intensified the urgency for carbon capture and storage (CCS), yet uncertainties remain in predicting evolution of reservoir properties under CO₂ injection. This study investigates how CO₂–brine–rock interactions alter porosity and permeability in carbonate and sandstone reservoirs. We quantify pore-scale changes and effects of CO₂-saturated brine on rock. In calcite-rich carbonates, CO₂-induced acidification enhances permeability through selective dissolution. Dolomite-rich samples and sandstones exhibit suppressed permeability response due to slower dissolution and pore clogging. μCT and SEM reveal that although bulk porosity changes are small, local changes—especially formation of micropores and mineral occlusions—substantially influence permeability. Geochemical modeling confirms three-stage evolution: early dissolution, intermediate buffering with onset of precipitation, and long-term mineral trapping with near-steady porosity. The results indicate that early injectivity gains may be temporary and that proactive monitoring and management are required to safeguard long-term storage integrity. The findings provide actionable insight for sustainable CCS design, risk assessment, and reservoir stewardship. Full article

Sulfate minerals (SMs), such as BaSO₄, SrSO₄, and CaSO₄, precipitate when incompatible solutions from the oil industry, such as seawater (SW) and high-salinity brine solutions (HSBSs), are mixed during the oil production process. To investigate the potentiality to extract SM by mixing three different brine solutions, such as HSBS-1, -2, and -3, with SW, at different temperatures and pressures, a practical simple model was used to predict the saturation index (SI), the quantity of precipitated minerals (Y), and the induction time (t_ind) required for precipitation. From the results, it was found that CaSO₄ hemihydrate and SrSO₄ yield lower amounts of precipitate. BaSO₄ precipitation ranges from 20 to 60 mg/L and 1500 mg/L of CaSO₄ anhydrous under ambient conditions. These findings suggest that recovering low-solubility minerals is technically feasible and environmentally preferable to direct disposal. Full article

Direct Contact Membrane Distillation–Crystallization (DCMD-Cr) is a synergistic technology for zero liquid discharge (ZLD) and resource recovery from high-salinity brines. In this study, DCMD-Cr was integrated to desalinate real oilfield-produced water (PW) with an initial salinity of 156,700 mg/L. The PW was concentrated to its saturation point of 28 wt.% via DCMD, and the integrated crystallization increased the overall water recovery from 42.0% to 98.9%, with a decline in water flux and salt rejection, mainly due to vapor pressure lowering and scaling. The precipitated salts in the crystallization unit were recovered and identified using different techniques. The results indicated that 91% of the crystals are sodium chloride, and less than 5% are calcium sulfate. A techno-economic analysis (TEA) was performed to evaluate the economic feasibility of the integrated DCMD-Cr process with a 500,000 gallons per day (GDP) capacity. The results showed that the crystallization operating cost was dominant at USD 0.50 per barrel, while the capital cost was only USD 0.04 per barrel. The economic viability can be enhanced by recovering value-added byproducts and using renewable or waste heat, which can reduce the total cost to USD 0.50 per barrel. Full article

This study aimed to evaluate the effect of using artisanal beers obtained from ricotta whey (scotta-based beer) during cheese affinage on the sensory properties of cheeses. For this purpose, four experimental groups of pressed cheeses were manufactured using two ripening techniques and a scotta-based brine. In detail, BB stands for experimental cheeses immersed in unsaturated beer brine; CB represents control cheeses immersed in unsaturated water brine; BWR corresponds to experimental cheeses with a washed rind using beer brine; and CWR denotes control cheeses with a washed rind using saturated water brine. The replacement of water with scotta-based beer in unsaturated brine, during cheese affinage, resulted in significant changes in the VOC profile of experimental cheeses, compared to control cheeses, with esters accounting for more than 60% of the total VOC area, imparting sweet and fruity notes. Sensory analysis revealed that beer-brined cheeses exhibited significantly different profiles (p < 0.05) across most evaluated attributes. Notably, the color of the rind and interior, as well as visual uniformity, were significantly enhanced by the beer brining, while oiliness was influenced by the ripening technique (p < 0.05) independently of the brine composition. Odor intensity and aroma complexity were markedly higher in beer-brined cheeses (p < 0.001), consistent with the migration of volatile compounds from beer into the cheese matrix. Among taste attributes, sourness, bitterness, and toasted flavor differed significantly (p < 0.05), with beer-brined cheeses perceived as less sour and more toasted. Washed-rind cheeses exhibited higher bitterness (p < 0.001), regardless of brining type. Furthermore, beer-brined cheeses showed increased hardness and plasticity, suggesting structural changes in the matrix. These findings support the potential of scotta-based beer-brining as a way to diversify cheese sensory profiles and enhance market value. Full article

Samples of gel-type cation exchangers of the TOKEM nomenclature were tested for lithium extraction from multicomponent natural brines. The dependencies of the extraction of Li and other impurities—Na, Ca, and Mg—on the duration of the sorption process for the tested ion-exchange resins under static conditions are presented. Metal ions can be arranged according to the degree of extraction for each ion exchanger in a row: Ca²⁺ < Mg²⁺ < Li⁺, Na⁺. Testing of ion exchangers under static conditions on technological Li-containing solutions confirms the applicability of TOKEM-140 and TOKEM-160 cation exchangers for lithium extraction. For TOKEM-140, lithium extraction over time varies from 76.2% to 73.8% and for TOKEM-160—from 73.8% to 72.4%. The ionic background of natural brines has a significant effect on the capacity of ion exchangers for lithium and forms the following series Li⁺ << Mg²⁺ < Ca²⁺ << Na⁺ relative to the obtained concentrations of metal ions in natural brine. The overlay of IR spectra of TOKEM-140 and TOKEM-160 ion exchangers before and after saturation shows slight changes in their appearance, indicating that the lithium sorption process has occurred. The values of static exchange capacity (SEC) for TOKEM-140 and TOKEM-160 cation exchangers are identical. Full article

In this research work, the electrochemical evaluation of a non-ionic gemini surfactant as a green corrosion inhibitor for X100 pipeline steel in CO₂-saturated brine solution was carried out by electrochemical impedance spectroscopy (EIS) and potentiodynamic polarization curves (PPC). The corrosion inhibition performance of the gemini surfactant was studied in static and hydrodynamic conditions at room temperature and 60 °C. Electrochemical measurements showed that the inhibitor’s performance was enhanced with increasing inhibitor concentration and with increasing exposure time at room temperature, reaching the highest inhibition efficiency (η) at 100 ppm. With increasing temperature, the inhibitor efficiency decreased, with similar behavior at all concentrations. The analysis of the cathodic polarization curves at different rotation speeds showed the strong influence of mass transport on the cathodic process in the absence and the presence of the inhibitor. Under hydrodynamic conditions, PPC and EIS results indicated that the best inhibitor performance was with a concentration of 50 ppm, achieving a maximum inhibition efficiency of 91%. The adsorption of the inhibitor molecules on the surface obeyed the Langmuir isotherm, and the type of adsorption was mixed in all the study conditions. Surface characterization by scanning electron microscopy (SEM) revealed the formation of a protective corrosion inhibitor film. Full article

We conducted ultrasonic (1-MHz) laboratory measurements on 210 samples from the Vaca Muerta Formation (Neuquén Basin, Argentina) to determine the factors influencing acoustic velocities in siliciclastic–carbonate mudstone. We quantitatively assessed the calcium carbonate and total organic carbon (TOC) content and qualitatively identified the quartz and clay mineralogy. For brine-saturated samples, P-wave velocities ranged from 2826 to 6816 m/s, S-wave velocities ranged from 1474 to 3643 m/s, and porosity values ranged from 0.01 to 19.4%. Carbonate content percentages, found to be critically important, vary widely from 0.08 to 98.0%, while TOC ranged from 0 to 5.3%. Velocity was primarily controlled by carbonate content and, to a lesser extent, by the non-carbonate mineralogy of the rock (e.g., quartz, clay minerals). TOC content had little effect on the acoustic properties. Due to the low porosity of most samples, mineral composition had a stronger influence on velocity than porosity or pore geometry. The V_p/V_s ratio of dry samples ranged from 1.38 to 1.97 and decreased as porosity increased. In saturated samples, the V_p/V_s ratio ranged from 1.46 to 2.06 and appeared independent of porosity. A clear distinction between carbonate and mixed lithofacies under both saturated and dry conditions was observed in all samples. Full article

Residual oil saturation in reservoirs is primarily influenced by viscous and capillary forces, with interfacial tension (IFT) being a critical factor in fluid distribution due to capillary pressure. Adjusting IFT is essential for enhancing oil recovery, particularly in waterflooding, which is the most common secondary recovery technique after primary production. The salinity of injected water directly affects the IFT between crude oil and brine, making it a crucial factor in optimizing recovery. However, limited studies have examined IFT using live oil samples under actual reservoir conditions. In this study, a high-pressure, high-temperature (HPHT) drop shape analyzer was used to measure the IFT between live oil and brine under reservoir conditions. Five live oil samples and two sodium chloride (NaCl) brine concentrations (30,000 and 100,000 ppm) were tested at a reservoir temperature of 180 °F. Measurements were conducted above the bubble points of the oils, replicating undersaturated reservoir conditions. The results revealed that the impact of pressure on IFT was more complex than that of salinity. IFT generally decreased with increasing pressure but showed mixed behavior across different samples. Conversely, IFT consistently increased with higher salinity. These findings enhance the understanding of IFT behavior under reservoir conditions, supporting improved reservoir simulations and oil recovery strategies. Full article

Exploration practice has proved that preservation conditions are one of the critical factors contributing to shale gas enrichment in the Middle Yangtze area. Well Yidi2 is the discovery well of Cambrian shale gas in this area. The paleo-fluid evolution and its implication for preservation conditions of shale gas remains unclear, posing challenges for shale gas exploration and development. In this study, through systematic analysis of fluid inclusions in fractrue-filling vein of the entire core section of this well, combined with carbon and oxygen isotope tests of veins and host rocks, a paleo-fluid profile was established to explore the formation environment of Cambrian paleo-fluids and their implications for the preservation conditions of the Shuijingtuo Formation (SJT Fm.) shale gas. The results suggest that fractures in the SJT Fm. shale at the base of Cambrian Series 2 mainly formed during the deep burial hydrocarbon generation stage, trapping a large number of liquid hydrocarbon inclusions. Subsequently, numerous high-density methane inclusions and a few of gas-liquid two-phase inclusions were trapped. The SO₄²⁻, Ca²⁺ and Mg²⁺ content of fluid inclusion groups in the veins decreased from the Qinjiamiao Formation (QJM Fm.) at the bottom of Cambrian Series 3 upward and downward respectively, and the rNa⁺/rCl⁻ ratio was the lowest in the SJT Fm. and increased overall upward. The δ¹³C values of calcite veins in Tianheban Formation (THB Fm.)-Shipai Formation (SP Fm.) of the middle Cambrian Series 2 and the Loushanguan Formation (LSG Fm.) of the Cambrian Series 3 were lighter compared to the host rocks. Results indicate the later tectonic activities in this area were relatively weak, and the shale interval remained in a state of high gas saturation for a long time. The QJM Fm. was the main source of high-salinity brine, and the SJT Fm. had strong self-sealing properties and was relatively less affected by external fluids. However, the pressure evolution of high-density methane inclusions in the SJT Fm. indicated that the pressure coefficient of the shale section significantly decreased during the Indosinian uplift and erosion stage. The veins in the THB-SP and LSG Fms. were closely related to the oxidation of hydrocarbon gases by TSR (thermochemical sulfate reduction) and the infiltration of atmospheric water, respectively. Therefore, the paleo-fluid in the fractures of Well Yidi2 have integrally recorded the whole geological process including the evolution from oil to gas, the backflow of high-salinity formation water, the upward escape of shale gas, and the process of shale gas reservoirs evolving from overpressure to normal pressure. Considering that Well Yidi2 area is located in a relatively stable tectonic setting, widely distributed fracture veins probably enhance the self-sealing ability, inhibiting the rapid escape of SJT Fm. shale gas. And the rapid deposition of Cretaceous also delayed the loss of shale gas to some extent. The combination of these two factors creates favorable preservation conditions of shale gas, establishing the SJT Fm. as the primary exploration target in this area. Full article

With the continuous development of the potash industry in salt lakes, the preparation of low-natrium salt for the green and environmentally friendly utilization of potassium and sodium resources in salt lakes has become a research hotspot. The primary method involves obtaining potassium brine from salt-lake brine through evaporation and then subjecting this mineral to transformation crystallization to obtain low-natrium salt crystals. In the crystallization vessel, a potassium−sodium-saturated solution is introduced, followed by the addition of an appropriate amount of water and solid magnesium chloride. After a thorough reaction, the solid−liquid separation yields the target product of low-natrium salt. Subsequently, the surface properties of KCl and NaCl crystals were calculated using first-principles methods. The research findings revealed that potassium chloride crystals, when they contained defects, readily adsorbed Na⁺ and NaCl. In a sodium−potassium-saturated system, KCl and NaCl easily formed heterojunctions, leading to embedded crystallization as the Mg²⁺ concentration increased in this saturated system. Feed rate and residence time directly affect the purity of low-natrium salt. A low-natrium salt meeting the requirements can be obtained after a residence time of more than 80 min under the following conditions. Full article

The permeability of a certain mudstone interlayer in underground salt cavern gas storage (Jintan, China) is slightly high, as indicated by pressure tests (leakage rate of approximately 1~2 L/d). This layer is referred to as the “Micro-Leakage Interlayer (MLI)”. The MLI significantly impacts the tightness of gas storage, potentially leading to substantial losses. To address this problem, an experimental study was conducted. Initially, a method utilizing brine crystallization to plug the micro-leakage interlayer (MLI) was proposed. After crystallization, the porosity of the MLI cores exhibited a notable increase, and the permeability of the MLI cores increased significantly, further exacerbating the risk of gas leakage. These results indicate that the plugging solution requires further exploration. Finally, a combined plugging solution utilizing brine crystallization and ultrafine cement was proposed. Using saturated brine and waterproof coatings, an ultrafine cement slurry was prepared, and specimens were created for testing. The results indicate that the specimens exhibited a porosity of approximately 3%, a permeability below 10⁻¹⁹ m², and a uniaxial compressive strength of about 40 MPa. The ultrafine cement particles had an average particle size of 3 µm, and the ultrafine cement slurry exhibited extremely low porosity and permeability, as well as high strength. The results indicate that this solution is highly feasible and can be applied to field engineering. Full article

This article presents findings from ongoing research on improving the efficiency of leaching salt caverns for brine production and creating storage spaces for gases or fuels. Previous studies of the authors highlighted the potential of modifying conventional technology by employing a high-pressure water jet to carve niches in salt rock. Current research aims to define precise niche parameters using innovative and enhanced Jet Cavern Technology (JCT). Our research identified improvements in leach efficiency across various configurations and quantities of niches. By analyzing three salt types—pink, spiz, and crystalline—it was demonstrated that creating a niche perpendicular to the well axis significantly reduces the time to achieve saturated brine by approximately 38%, particularly during the initial construction phase. Further adjustments in niche dimensions, spacing, or spatial positioning can improve cavern construction rates by up to 20% over standard methods. This study quantified the correlation between the advancement of the process and the rate of increase in the salt content in the brine. Accelerated brine saturation facilitates cavern construction and mitigates environmental concerns associated with the discharge of unsaturated brine. The adoption of this new technology is crucial for the expansion of renewable energy sources and the associated storage requirements. Full article