Search Results (946)

Enhanced oil recovery (EOR) is a crucial technology for improving crude oil recovery; it extracts residual oil from reservoirs through chemical, physical, or biological methods, thereby further increasing recovery rates after secondary recovery. Biosurfactants, particularly lipopeptides, have become a research focus in the field of EOR due to their excellent properties. However, existing studies have mainly concentrated on their production and characterization, while systematic investigation into their deactivation mechanisms and stability limits remains lacking at the molecular level. This study integrates density functional theory (DFT), ab initio molecular dynamics (AIMD), and classical molecular dynamics (MD) simulations to systematically reveal the hydrolysis mechanisms and stability boundaries of lipopeptide model molecules under high-temperature and high-salinity reservoir conditions from a multiscale perspective. DFT calculations show significant differences in the energy barriers among different hydrolysis sites in lipopeptide molecules, with side-chain structure being a key factor influencing amide bond hydrolysis. Metal ions present in reservoir environments (Na⁺, K⁺, Ca²⁺, Mg²⁺), particularly divalent ones (Ca²⁺, Mg²⁺), can act as catalysts to reduce the hydrolysis energy barrier. Electronic structure analysis reveals that the catalytic effect originates from the polarization of the carbonyl oxygen by metal ions, weakening the covalent character of the C=O bond. AIMD simulations reveal that only Ca²⁺ can specifically activate the hydrolysis of lipopeptide molecules at certain distances (critical distance), while other cations (e.g., Mg²⁺, K⁺, Na⁺) do not exhibit similar catalytic activity. MD simulations further demonstrate that Ca²⁺ ion concentration and temperature are the dominant factors influencing Ca²⁺ permeation toward hydrolysis sites (limit distance), with other ions having a weaker effect. By systematically simulating lipopeptide behavior under varying temperature and ion concentration conditions, a catalytic hydrolysis criterion based on the effective distance of Ca²⁺ interaction (i.e., limit distance ≤ critical distance) is established through multiscale simulation, and the performance boundaries of its temperature and salt tolerance are preliminarily defined. This study provides a theoretical basis and quantitative design guidance for the applicability of lipopeptide-based biosurfactants in high-temperature and high-salinity reservoirs. Full article

Conventional Rate Transient Analysis (RTA) models, based on homogeneous fracture assumptions, are inadequate for characterizing flow in complex fracture networks of heterogeneous unconventional reservoirs. This study develops a fractal-based RTA (FD-RTA) workflow integrating lithofacies analysis, microseismic fracture interpretation, and post-fracturing production data from the Yingxiongling shale oil field in the Q’aidam Basin. The workflow is applied to eight horizontal wells completed in layered and laminated dolomites. Results show that the two lithofacies exhibit distinct fractal flow behaviors. Layered dolomite tends to develop preferential flow pathways, characterized by rapid initial depletion followed by declining supply capacity, with the half-flow dimension (δ) decreasing from 0.299 to 0.074 during production. Laminated dolomite displays stronger fracture-matrix interaction and sustained production performance, with δ increasing from 0.469 to 0.678 as multi-scale fractures are progressively activated. The FD-RTA workflow effectively links fracture complexity with production behavior, providing a dynamic characterization tool for evaluating hydraulic fracturing effectiveness in shale oil reservoirs. Full article

Severe steam channeling in heterogeneous heavy oil reservoirs severely restricts thermal recovery efficiency, as conventional conformance control materials cannot simultaneously achieve long-term high-temperature resistance and deep reservoir penetration. This work develops a high-temperature-resistant epoxy-based liquid microsphere system for deep profile control in heavy oil steam flooding. A triple thermal-stabilization strategy is constructed: imide chain extension to enhance backbone rigidity, benzoxazine-phthalonitrile grafting to form dense triazine crosslinked networks, and KH-550-functionalized nano-silica for synergistic reinforcement. FT-IR and ¹H NMR verify the successful incorporation of rigid imide and triazine structures. TGA confirms the optimal formulation exhibits less than 5% mass loss at 350 °C. Multi-segment sand-packed tube tests demonstrate favorable deep migration capacity with inter-stage pressure ratios below 4 across 5000–15,000 × 10⁻³ μm² permeability, and the cured network retains over 95% plugging efficiency after 350 °C steam scouring. Dual-tube heterogeneous flooding delivers 12.05% incremental oil recovery, outperforming rigid inorganic particles. This system provides a high-performance candidate for deep steam channeling mitigation in heavy oil thermal recovery. Full article

Oil-based mud filtrate (OBMF) invasion significantly alters the petrophysical response of nuclear magnetic resonance (NMR) logging, severely compromising the accuracy of reservoir fluid identification and petrophysical evaluation. However, the NMR relaxation behavior of OBMF under elevated temperatures (up to 100 °C) and low-frequency (<2 MHz) conditions remains poorly understood. In this study, temperature-dependent NMR experiments were conducted from 30 °C to 100 °C at a fixed frequency of 21 MHz, while frequency-dependent experiments were performed from 1 MHz to 21 MHz at 30 °C. Using combined analysis of T₂ spectra and T₂-T₁ two-dimensional spectra, the effects of temperature and magnetic field frequency on the relaxation characteristics of OBMF were investigated under the conditions of this study. The results show that increasing temperature shifts the T₂ distribution toward longer relaxation times, with the T₂ geometric mean increasing from 35 ms to approximately 113 ms, exhibiting an exponential relationship (R² = 0.996). T₁ values increase from 368 ms to 589 ms, while the T₁/T₂ ratio decreases from 11.2 to 5.8. In contrast, decreasing frequency prolongs T₂ relaxation times, with the T₂ geometric mean following a power-law relationship with frequency. Based on these experimental findings, a dual-parameter model incorporating both temperature and frequency was established for OBMF. The proposed model serves as a theoretical reference for the analysis and correction of NMR logging data acquired under oil-based mud invasion conditions. Full article

Parameter sensitivity analysis is a critical step in the numerical simulation and parameter design of CCUS models for high-temperature oil reservoirs. Owing to the complexity of these models, a single simulation run is computationally expensive, and sensitivity analysis typically requires numerous model evaluations, making the process both time-consuming and labor-intensive. Moreover, conventional sensitivity analysis methods often fail to identify which parameter most significantly influences development performance when multiple parameters are considered simultaneously. To address these challenges, the paper focuses on high-temperature oil reservoirs and establishes a comprehensive numerical model. Meanwhile, the BP neural network is employed to construct the proxy model, and the Sobol global sensitivity analysis method is used to perform sensitivity analysis. In the analysis, multiple parameters, including reservoir heterogeneity, CO₂ injection rate, liquid production rate, and CO₂ injection purity, were simultaneously evaluated to assess their impact on oil recovery, CO₂ geological storage capacity, and CO₂ heat recovery. The results indicate that the CO₂ injection rate, liquid production rate, and CO₂ injection purity exert the greatest influence on CCUS development performance in high-temperature reservoirs. Compared with traditional parameter sensitivity analysis techniques, the combination of the BP neural network proxy model and the Sobol method delivers high-precision sensitivity results while reducing computation time to only 40.7% of that required by conventional approaches, thus significantly saving both computational effort and time. Full article

To address the unclear microscopic mechanisms of water huff-n-puff in tight reservoirs under the influence of salinity, a visual physical model for microscopic flow in fracturing fluid displacement was constructed. It was clarified that the fluid displacement mechanism during fracturing fluid displacement is jointly governed by three mechanisms: pressure differential displacement, capillary force imbibition, and ion osmosis, which breaks through the traditional understanding only considering “fracturing fluid displacement and imbibition for energy supplementation.” Through multi-method and multi-scale approaches, the microscopic mobilization mechanism of fracturing fluid displacement under the influence of salinity was elucidated, and the main controlling factors were analyzed. The results indicate that reducing the salinity of injected water can enhance oil recovery, and the recovery factor increases with reservoir permeability, shut-in time, and injection pressure. Reservoir permeability and injected water salinity have a greater impact on the performance of water huff-n-puff, followed by shut-in time and injection pressure. Although low-salinity water flooding tends to induce viscous fingering, which reduces the sweep efficiency of the injected water, it enhances capillary imbibition, effectively stripping residual oil from low-permeability matrices and dead-end pores, thereby ultimately improving oil recovery. This study provides theoretical support for enhancing recovery in tight oil reservoirs using fracturing fluid displacement. Full article

Petroleum reservoir systems of the South Mangyshlak Basin are characterized by a complex geological framework, pronounced geochemical heterogeneity, and evidence of inter-reservoir fluid interactions, which complicate the interpretation of oil origin and the assessment of geochemically inferred reservoir connectivity between productive horizons. In this study, a comprehensive geochemical characterization of crude oils from the basin was performed using high-resolution gas chromatography (HRGC), gas chromatography–mass spectrometry (GC–MS), oil fingerprinting, and Rock-Eval pyrolysis. The distributions of n-alkanes, isoprenoids, terpane, sterane, and aromatic biomarker compounds were analyzed to evaluate the genetic type of the source organic matter, thermal maturity, and hydrocarbon migration processes. The results revealed the presence of marine, lacustrine, and mixed genetic oil families, together with a general tendency toward increasing thermal maturity with reservoir depth. The most pronounced evidence of vertical hydrocarbon migration and oil mixing was identified in the Uzen oil field, where the multilayer reservoir system exhibits geochemical evidence consistent with possible inter-reservoir fluid communication and geochemically inferred reservoir connectivity. The obtained results suggest that the geochemical heterogeneity of oils in the South Mangyshlak Basin reflects the combined effects of variations in source-rock organic matter, vertical hydrocarbon migration, and oil mixing within stacked petroleum reservoir systems. Full article

Oil–water relative permeability is a critical parameter for reservoir fluid property evaluation and productivity prediction, playing a vital role in reservoir identification and development. However, the correlation between relative permeability and resistivity remains unclear for complex conductive mineral-bearing argillaceous sandstone reservoirs. In this study, twenty-eight artificial core samples were prepared and compacted under simulated reservoir temperature and pressure conditions. Simultaneous oil–water relative permeability and resistivity measurements were performed on these samples at two brine salinities (7000 ppm and 3000 ppm). The analysis reveals that under the same resistivity index, both conductive-mineral content and shale content exhibit a negative correlation with water-phase relative permeability but a positive correlation with oil-phase relative permeability. In contrast, porosity–permeability conditions and injected-water salinity show a positive correlation with water-phase relative permeability and a negative correlation with oil-phase relative permeability. Furthermore, the effect of salinity on the relative permeability–resistivity relationship intensifies as porosity–permeability conditions improve. Based on the consistency between movable water seepage and conductive paths, a novel relative permeability–resistivity model was developed for the target reservoirs by integrating seepage and conductive theories, with a generalized Archie’s equation adopted to calibrate the effects of conductive minerals and shale on rock conductivity. The model parameters are optimized using the Newton–Raphson iteration algorithm, and empirical correlations between the undetermined coefficients and reservoir parameters are developed. Validated against two independent cores with the most complex mineral compositions (SH2-3 and SH3-3), the model yields average relative errors of 9.8% and 13.4% for water-phase relative permeability, and 4.4% and 5.4% for oil-phase relative permeability, respectively, demonstrating its high calculation accuracy. It enables efficient prediction of reservoir relative permeability using resistivity data, providing a new theoretical and technical support for low-resistivity oil reservoir identification and productivity assessment. Full article

This study presents an integrated geochemical approach to distinguish between genetic and reservoir-related factors controlling oil compositional variability, evaluate reservoir compartmentalization, and reconstruct hydrocarbon migration pathways within the Nuraly field and the Akshabulak group of fields in the South Turgay Basin, Kazakhstan. The study aims to develop and validate an integrated approach combining biomarker analysis and oil fingerprinting to improve the reliability of oil genetic interpretation, assess reservoir fluid communication, and reconstruct secondary hydrocarbon migration pathways. This study analyzed 164 unique crude oil samples from the Akshabulak and Nuraly fields. Oil fingerprinting was performed on all 164 samples, including 128 samples from the Akshabulak group and 36 samples from the Nuraly field. A representative subset of 75 samples, comprising 39 Akshabulak oils and 36 Nuraly oils, was additionally analyzed for biomarkers. Oil fingerprinting was conducted using low thermal mass multidimensional gas chromatography (LTM-MD-GC), whereas biomarker analysis was performed using gas chromatography–mass spectrometry (GC–MS). Principal component analysis (PCA) and hierarchical cluster analysis were applied separately to the oil-fingerprinting and biomarker datasets. The resulting classifications were subsequently compared and integrated to distinguish source-related genetic variability from reservoir-related compositional effects, including hydrocarbon migration, oil mixing, and reservoir compartmentalization. The proposed approach is based on the complementary diagnostic capabilities of the applied geochemical methods. Biomarkers provide information on the origin of organic matter, depositional environment, and thermal maturity of the source rocks, whereas oil fingerprinting is sensitive to hydrocarbon migration processes and the degree of hydrodynamic connectivity between reservoirs. The results indicate that the investigated oils are predominantly derived from terrigenous organic matter of lacustrine origin. The Akshabulak group is characterized by genetic homogeneity of oils despite pronounced reservoir compartmentalization, whereas the Nuraly field contains at least two genetically distinct oil populations and hydrocarbon mixing zones. Regional hydrocarbon migration was reconstructed from southeast to northwest. Paleochannel sandstones were identified as high-permeability migration conduits, while tectonic faults and facies heterogeneity were recognized as the principal controls on reservoir hydrodynamic isolation. The results demonstrate that integrating biomarker analysis with oil fingerprinting provides an effective tool for distinguishing between genetic and reservoir-related controls on oil compositional variability, evaluating reservoir compartmentalization, and improving the reliability of geological and reservoir models in structurally complex petroleum systems. Full article

The efficient development of heavy oil reservoirs is challenged by the high viscosity and poor mobility of heavy oil. Although multicomponent thermal fluid technologies involving heat, gas, and chemical agents have demonstrated potential advantages over conventional steam-based recovery methods, the microscopic synergistic mechanisms responsible for viscosity reduction remain insufficiently understood. Therefore, this study investigates the synergistic mechanisms by which heat, an alkane solvent (C₁₁H₂₄), and CO₂ reduce heavy-oil viscosity. Heavy oil from the Shengli Oilfield was selected as the research object, and rheological experiments were combined with molecular dynamics simulations to systematically analyze viscosity variations and their underlying microscopic mechanisms under different conditions. The experimental results demonstrate that increasing temperature significantly reduces heavy oil viscosity, and a characteristic transition in viscosity reduction behavior occurs at approximately 100 °C. At 90 °C, the addition 5 wt% oil-soluble viscosity reducer C₁₁H₂₄ decreases the heavy oil viscosity to 442.2 mPa·s, corresponding to a reduction rate of 83%. The solubility of CO₂ increases markedly with pressure, and at 30 MPa, the viscosity reduction exceeds 99%. The combined effects of these three factors exhibit superior viscosity-reduction performance. Molecular dynamics simulation results indicate that CO₂ and the viscosity reducer synergistically weaken the π-π stacking interactions of asphaltenes and resins in heavy oil, transforming heavy components from locally aggregated states into more uniformly dispersed configurations. Meanwhile, the intermolecular interaction energy and cohesive energy density decrease, indicating weakened molecular interactions and enhanced diffusion behavior. These results demonstrate that the synergistic viscosity-reduction mechanism of heat–gas–agent systems is mainly associated with structural disaggregation, interaction weakening, and diffusion enhancement. This study provides molecular-level insights into multicomponent thermal fluid-assisted heavy oil recovery and offers theoretical support for improving heavy oil development efficiency. Full article

Middle-phase (Winsor III) microemulsion flooding is a promising technique for enhanced oil recovery (EOR). However, the presence of natural polar components in crude oil and varying reservoir salinity complicate the formulation of optimal microemulsion systems. This study experimentally investigates the effects of salinity and organic acids (lauric acid and caprylic acid) on the phase behavior of a microemulsion system composed of sodium dodecyl sulfonate (SDS), n-butanol, and different oils. Phase behavior experiments revealed that the optimal salinity window for middle-phase formation increases with the carbon number of the oil phase, expanding from 3–6.6 to 4–8.5 and 6–11.8 g/100 mL for octane, decane, and dodecane, respectively. The addition of polar acids was found to narrow this optimal salinity range; in particular, for decane, an increase in lauric acid concentration from 0.1% to 0.9% narrowed the salinity window from 4–8 to 4–6 g/100 mL, making the microemulsion systems more sensitive to salinity changes. Subsequent core flooding experiments demonstrated that the presence of polar components enhances the ultimate oil recovery, with higher acid concentrations leading to faster production rates. Furthermore, the EOR performance was shown to be highly dependent on salinity, peaking within the optimal salinity range that promotes a stable Winsor III microemulsion, leading to an ultimate recovery as high as 68.8%. These findings provide crucial insights for designing robust surfactant formulations for EOR in reservoirs containing polar crude oils. Full article

For tight oil reservoirs, analyzing the characteristics of the Blasingame production decline curves of production wells under CO₂ flooding can effectively evaluate the development performance of CO₂ miscible flooding. However, tight oil reservoirs exhibit stress-sensitive effects, which degrade the reliability of interpretation results. Currently, there are few production decline analysis models for CO₂ miscible flooding that consider stress sensitivity. Based on the flow theory of three-region composite reservoirs, a physical model for CO₂ miscible flooding considering stress-sensitive effects was designed, and a mathematical model was established to obtain the characteristics of the Blasingame curve. The results show that the production decline analysis model for CO₂ miscible flooding is divided into six flow stages; the stress-sensitive effect causes the entire Blasingame curve to shift downwards; the mobility ratio and storativity ratio have a significant impact on the entire flow process of CO₂ miscible flooding. The proposed production decline analysis model provides a potential method for estimating the effective front radii of the crude oil region and the transition region, together with other equivalent flow parameters, from production data. Full article

In carbonate petroleum reservoirs, permeability impairment caused by asphaltene precipitation and deposition remains a major challenge that limits long-term productivity. This study introduces a green polymeric nanocomposite (KCl/SiO₂/Xanthan/Origanum vulgare, NCs) designed to control interfacial dynamics and preserve flow capacity in carbonate formations. Using a multi-technique approach—interfacial tension (IFT) analysis, atomic force microscopy (AFM), and rock-core, fluid-flooding experiments at simulated subsurface conditions—the NCs’ abilities were evaluated in terms of their potential to modify properties at fluid–fluid and fluid–rock interfaces. The NCs increased the CO₂–brine/oil IFT slope in certain pressure regions by up to 40.77%. These results indicate competitive adsorption that stabilizes interfaces. Adsorption isotherms confirmed a monolayer mechanism with a high capacity of 294.12 mg/g. AFM topographic mapping revealed order-of-magnitude changes in surface roughness (reductions in average roughness by ~75%, root-mean-square by ~83%, peak-to-valley by ~93%). These results directly link nanoscale smoothing to reduced capillary pinning. Core flooding tests demonstrated that NCs treatment decreased formation damage by up to 67.45% at 4000 psi, maintaining a high permeability ratio (k/k_i = 0.87) and preserving porosity (φ/φ_i = 0.887, representing 88.7% porosity retention). These results establish that the studied NCs coherently manipulate fluid physics in relation to molecular adsorption and macroscopic permeability. Consequently, these NCs offer a sustainable, high-performance strategy for flow assurance and formation damage control in geological and geothermal reservoirs. Full article

Complex narrow-channel reservoirs are strongly constrained by depositional architecture, resulting in highly nonuniform areal waterflood sweep, and pronounced water-cut variations among different channel types. These characteristics pose substantial challenges to stabilizing oil production and controlling water cut at high water-cut stages. To elucidate how narrow-channel planform architecture controls waterflood sweep, gel-assisted flow-field regulation by heterogeneous-phase composite flooding (HPCF), and remaining-oil mobilization, three representative configurations were reproduced in two-dimensional visual physical models. Sequential waterflood–HPCF–post-waterflood experiments were conducted, and time-lapse images and dynamic production data were integrated to characterize sweep evolution and remaining-oil mobilization across displacement stages. The results demonstrate that narrow-channel architecture exerts primary control on preferential flow-path development, gel migration and retention, spatial fluid redistribution, and displacement performance. During waterflooding, injected water preferentially migrated through high-permeability zones along channel centerlines, leaving channel margins, branch termini, and poorly connected regions insufficiently swept. After HPCF injection, the gel-containing composite system preferentially entered the established dominant flow paths. Gel retention and accumulation selectively increased flow resistance in these pathways, while mobility control induced subsequent fluids to divert toward bypassed regions, thereby enlarging the macroscopic swept volume and improving local displacement efficiency. A low injection rate promoted sustained gel-assisted flow diversion within bifurcated channels, whereas a high injection rate facilitated gel-slug propagation against the geometric constraints of highly sinuous channels and expanded its spatial coverage. Compared with waterflooding alone, HPCF increased the ultimate oil recovery of the three channel models by 19.23–26.47 percentage points. These findings clarify the coupled effects of narrow-channel architecture, gel transport and injection parameters on the profile-control and oil-recovery performance of HPCF, providing a mechanistic basis for water control and development optimization in high-water-cut narrow-channel reservoirs. Full article

In the development of carbonate reservoirs via water flooding huff-n-puff, the osmotic pressure effect is frequently overlooked, and existing models inadequately quantify the matrix imbibition and oil expulsion driven by salinity gradients. To address this issue, this study establishes a coupled oil–water two-phase huff-n-puff flow model for carbonate reservoirs that incorporates the interplay between salt concentration and osmotic pressure, which, for the first time, fully couples the van ’t Hoff osmotic pressure equation with solute transport equations for fractured-vuggy carbonate huff-n-puff, filling the gap that prior tight/shale reservoir low-salinity flow models fail to adapt to cyclic injection-soaking production regimes of carbonates. Based on the IMPES (implicit pressure–explicit saturation) numerical simulation method, an equivalent single-nucleus model is adopted to characterize the fractured-vuggy reservoir architecture. The model integrates the osmotic pressure formula, solute transport equation, and two-phase seepage governing equations, enabling a systematic analysis of the mechanisms by which osmotic pressure affects the multi-stage seepage process and the influence of key parameters on development performance. Quantitative simulation reveals three core laws controlled by salinity-induced osmosis: first, osmotic pressure drives water molecules to spontaneously migrate from the high-permeability fracture inner core toward the tight matrix pores, thereby modifying the water saturation distribution, expanding the water sweep region, and smoothing the saturation gradient between the inner and outer cores, which effectively mitigates water channeling in fractured reservoirs. Under the base case (injected water salinity = 1000 mg/L, inner-core permeability = 1000 mD, shut-in time = 80 d), the oil recovery factor with osmotic pressure considered reaches 13.46%, representing a 3.50% increment over the case without osmotic pressure. The recovery factor decreases monotonically with increasing injected water salinity, while it increases with longer shut-in time and higher inner-core permeability, both exhibiting pronounced diminishing marginal returns; the optimal shut-in time is approximately 80 d under the simulated conditions. This work delivers a fully coupled numerical tool and quantitative evaluation standard for osmotic imbibition mechanisms in fractured-vuggy carbonates. The quantified recovery increment and optimal soaking window established herein can directly guide field parameter optimization of injection water salinity, shut-in cycle and fracture reconstruction scale, balancing oil increment revenue and water treatment/well shutdown operation costs for on-site low-salinity huff-n-puff design. Full article