Search Results (104)

The Threshold Pressure Gradient (TPG) phenomenon exerts a profound influence on fluid flow dynamics in heavy oil reservoirs. However, the discrepancies between the True Threshold Pressure Gradient (TTPG) and Pseudo-Threshold Pressure Gradient (PTPG) significantly impede accurate residual oil evaluation and rational field development planning. This study proposes a dual-exponential conversion model that effectively bridges the discrepancy between TTPG and PTPG, achieving an average deviation of 12.77–17.89% between calculated and measured TTPG values. Nonlinear seepage simulations demonstrate that TTPG induces distinct flow barrier effects, driving residual oil accumulation within low-permeability interlayers and the formation of well-defined “dead oil zones.” In contrast, the linear approximation inherent in PTPG overestimates flow initiation resistance, resulting in a 47% reduction in recovery efficiency and widespread residual oil enrichment. By developing a TTPG–PTPG conversion model and incorporating genuine nonlinear seepage characteristics into simulations, this study effectively mitigates the systematic errors arising from the linear PTPG assumption, thereby providing a scientific basis for accurately predicting residual oil distribution and enhancing oil recovery efficiency. Full article

Channeling in cementing causes interlayer interference, severely restricting oilfield recovery. Existing channeling plugging agents, such as cement and gels, often lead to reservoir damage or insufficient strength. Oil-soluble resin (OSR) particles show great potential in selective plugging of channeling fractures due to their excellent oil solubility, temperature/salt resistance, and high strength. However, their application is limited by the efficient filling and retention in deep fractures. This study innovatively combines the OSR particle plugging system with the mature rapid filtration loss plugging mechanism in drilling, systematically exploring the influence of particle size and sorting on their filtration, packing behavior, and plugging performance in channeling fractures. Through API filtration tests, visual fracture models, and high-temperature/high-pressure (100 °C, salinity 3.0 × 10⁵ mg/L) core flow experiments, it was found that well-sorted large particles preferentially bridge in fractures to form a high-porosity filter cake, enabling rapid water filtration from the resin plugging agent. This promotes efficient accumulation of OSR particles to form a long filter cake slug with a water content <20% while minimizing the invasion of fine particles into matrix pores. The slug thermally coalesces and solidifies into an integral body at reservoir temperature, achieving a plugging strength of 5–6 MPa for fractures. In contrast, poorly sorted particles or undersized particles form filter cakes with low porosity, resulting in slow water filtration, high water content (>50%) in the filter cake, insufficient fracture filling, and significantly reduced plugging strength (<1 MPa). Finally, a double-slug strategy is adopted: small-sized OSR for temporary plugging of the oil layer injection face combined with well-sorted large-sized OSR for main plugging of channeling fractures. This strategy achieves fluid diversion under low injection pressure (0.9 MPa), effectively protects reservoir permeability (recovery rate > 95% after backflow), and establishes high-strength selective plugging. This study clarifies the core role of particle size and sorting in regulating the OSR plugging effect based on rapid filtration loss, providing key insights for developing low-damage, high-performance channeling plugging agents and scientific gradation of particle-based plugging agents. Full article

Surfactants can be utilized to improve oil recovery by changing the performance of reservoirs in rock pores. Kerogen is the primary organic matter in shale; however, high temperatures will affect the overall performance of this surfactant, resulting in a decrease in its activity or even failure. The effect of surfactants on kerogen pyrolysis has rarely been researched. Therefore, this study synthesized a polymeric surfactant (PS) with high temperature resistance and investigated its effect on kerogen pyrolysis under the friction of drill bits or pipes via molecular dynamics. The infrared spectra and thermogravimetric and molecular weight curves of the PS were researched, along with its surface tension, contact angle, and oil saturation measurements. The results showed that PS had a low molecular weight, with an MW value of 124,634, and good thermal stability, with a main degradation temperature of more than 300 °C. It could drop the surface tension of water to less than 25 mN·m⁻¹ at 25–150 °C, and the use of slats enhanced its surface activity. The PS also changed the contact angles from 127.96° to 57.59° on the surface of shale cores and reversed to a water-wet state. Additionally, PS reduced the saturated oil content of the shale core by half and promoted oil desorption, indicating a good cleaning effect on the shale oil reservoir. The kerogen molecules gradually broke down into smaller molecules and produced the final products, including methane and shale oil. The main reaction area in the system was the interface between kerogen and the surfactant, and the small molecules produced on the interface diffused to both ends. The kinetics of the reaction were controlled by two processes, namely, the step-by-step cleavage process of macromolecules and the side chain cleavage to produce smaller molecules in advance. PS could not only desorb oil in the core but also promote the pyrolysis of kerogen, suggesting that it has good potential for application in shale oil exploration and development. Full article

Unconventional hydrocarbon reservoirs with low matrix permeability (<0.3 mD), high temperatures, and sour conditions present significant challenges for stimulation and production enhancement. This study examines field trials for a large oil and gas operator in the UAE, focusing on tight carbonate deposits with reservoir temperatures above 93 °C and high sour gas content. A novel multi-stage chemical stimulation workflow was created, beginning with a pre-flush phase that alters rock wettability and reduces interfacial tension at the micro-scale. This was followed by a second phase that increased near-wellbore permeability and ensured proper acid placement. The treatment’s core used a thermally stable, corrosion-resistant retarded acid system designed to slow reaction rates, allow deeper acid penetration, and build prolonged conductive wormholes. Simulations revealed considerable acid penetration of the formation beyond the near-wellbore zone. The post-treatment field data showed a tenfold improvement in injectivity, which corresponded closely to the acid penetration profiles predicted by modeling. Furthermore, oil production demonstrated sustained, high oil production of 515 bpd on average for several months after the treatment, in contrast to the previously unstable and low-rate production. Finally, the findings support a reproducible and technologically advanced stimulation technique for boosting recovery in ultra-tight carbonate reservoirs using the acid retardation effect where traditional stimulation fails. Full article

As an important unconventional oil and gas resource, tight oil exploration and development is of great significance to ensure energy supply under the background of continuous growth of global energy demand. Low-porosity and low-permeability reservoirs are characterized by tight rock properties, poor physical properties, and complex pore structure, and as a result the fine calculation of logging reservoir parameters faces great challenges. In addition, the crude oil in this area has high viscosity, the formation water salinity is low, and the oil reservoir resistivity shows significant spatial variability in the horizontal direction, which further increases the difficulty of oil and water reservoir identification and affects the accuracy of oil saturation calculation. Targeting the above problems, the Nutcracker Optimization Algorithm (NOA) was used to optimize the hyperparameters of the random forest classification model, and then the optimal hyperparameters were input into the random forest model, and the conventional logging curve and oil test data were combined to identify and classify the reservoir fluids, with the final accuracy reaching 94.92%. Compared with the traditional Hingle map intersection method, the accuracy of this method is improved by 14.92%, which verifies the reliability of the model for fluid identification of low-porosity and low-permeability reservoirs in the research block and provides reference significance for the next oil test and production test layer in this block. Full article

Aiming at the problems of insufficient natural productivity and large seepage resistance in low-permeability oil and gas reservoirs, a nano relative permeability improver based on nano SiO₂ was developed in this study. The nano relative permeability improver was prepared by the reversed-phase microemulsion method, and the formula was optimized (nano SiO₂ 5.1%, Span-80 33%, isobutanol 18%, NaCl 2%), so that the minimum median particle size was 4.2 nm, with good injectivity and stability. Performance studies showed that the improvement agent had low surface tension (30–35 mN/m) and interfacial tension (3–8 mN/m) as well as significantly reduced the rock wetting angle (50–84°) and enhanced wettability. In addition, it had good temperature resistance, shear resistance, and acid-alkali resistance, making it suitable for complex environments in low-permeability reservoirs. Full article

In order to improve oil recovery efficiency in low-permeability reservoirs, this study developed amphiphilic Janus-SiO₂ nanoparticles to prepare polymer gel microspheres for enhanced oil recovery (EOR). Firstly, Janus-SiO₂ nanoparticles were synthesized via surface modification using (3-aminopropyl)triethoxysilane and α-bromoisobutyryl bromide. Fourier-transform infrared spectroscopy (FTIR) and scanning electron microscopy (SEM) characterization confirmed the successful grafting of amino and styrene chains, with the particle size increasing from 23.8 nm to 32.9 nm while maintaining good dispersion stability. The Janus nanoparticles exhibited high interfacial activity, reducing the oil–water interfacial tension to 0.095 mN/m and converting the rock surface wettability from oil-wet (15.4°) to strongly water-wet (120.6°), thereby significantly enhancing the oil stripping efficiency. Then, polymer gel microspheres were prepared by reversed-phase emulsion polymerization using Janus-SiO₂ nanoparticles as emulsifiers. When the concentration range of nanoparticles was 0.1–0.5 wt%, the particle size range of polymer gel microspheres was 316.4–562.7 nm. Polymer gel microspheres prepared with a high concentration of Janus-SiO₂ nanoparticles can ensure the moderate swelling capacity of the particles under high-temperature and high-salinity conditions. At the same time, it can also improve the mechanical strength and shear resistance of the microspheres. Core displacement experiments confirmed the dual synergistic effect of this system. Polymer gel microspheres can effectively plug high-permeability zones and improve sweep volume, while Janus-SiO₂ nanoparticles enhance oil displacement efficiency. Ultimately, this system achieved an incremental oil recovery of 19.72%, exceeding that of conventional polymer microsphere systems by more than 5.96%. The proposed method provides a promising strategy for improving oil recovery in low-permeability heterogeneous reservoir development. Full article

Water injection is the most widely used secondary recovery method, but its low viscosity limits sweep efficiency in heterogeneous carbonate reservoirs, especially when displacing heavy crude oils. Polymer flooding overcomes this by increasing the viscosity of the injected fluid and improving the mobility ratio. In this work, we compare three biopolymers (i.e., Xanthan Gum, Scleroglucan, and Guar Gum) using a core flood test on Indiana Limestone with 16–19% porosity and 180–220 mD permeability at 60 °C and 30,905 mg/L of salinity. We injected solutions at 100–1500 ppm and 0.5–6 cm³/min to measure the Resistance Factor (RF), Residual Resistance Factor (RRF), in situ viscosity, and relative injectivity. All polymers behaved as pseudoplastic fluids with no shear thickening. The RF rose from ~1.1 in the dilute regime to 5–16 in the semi-dilute regime, and the RRF spanned 1.2–5.8, indicating moderate, reversible permeability impairment. In-site viscosity reached up to eight times that of brine, while relative injectivity remained 0.5. Xanthan Gum delivered the highest viscosity boost and strongest shear thinning, Scleroglucan offered a balance of stable viscosity and a moderate RF, and Guar Gum gave predictable but lower viscosity enhancement. These results establish practical guidelines for selecting polymer types, concentration, and flow rate in reservoir-condition polymer flood designs. Full article

To address the challenges of low displacement efficiency and gas channeling in the Lukqin thick oil reservoir, characterized by high viscosity (286 mPa·s) and strong heterogeneity (permeability contrast 5–10), this study systematically investigated water flooding and foam flooding mechanisms using a large-scale 2D sandpack model (5 m × 1 m × 0.04 m). Experimental results indicate that water flooding achieves only 30% oil recovery due to a mobility ratio imbalance (M = 128) and preferential channeling. In contrast, foam flooding enhances recovery by 15–20% (final recovery: 45%) through synergistic mechanisms of dynamic high-permeability channel plugging and mobility ratio optimization. By innovatively integrating electrical resistivity tomography with HSV color mapping, this work achieves the first visualization of foam migration pathways in meter-scale heterogeneous reservoirs at a spatial resolution of ≤0.5 cm, reducing monitoring costs by approximately 30% compared to conventional CT techniques. Key controlling factors for gas channeling (injection rate, foam quality, permeability contrast) are identified, and a nonlinear predictive model for plugging strength ((S = 0.70C^0.6 k_r^−0.28) (R² = 0.91)) is established. A composite optimization strategy—combining high-concentration slugs (0.7% AOS), salt-resistant polymer-enhanced foaming, and multi-round profile control—achieves a 67% reduction in gas channeling. This study elucidates the dynamic plugging mechanisms of foam flooding in heterogeneous thick oil reservoirs through large-scale physical simulations and data fusion, offering direct technical guidance for optimizing foam flooding operations in the Lukqin Oilfield and analogous reservoirs. Full article

Electrical imaging logging technology precisely characterizes the features of the formation on the borehole wall through high-resolution resistivity images. However, the problem of blank strips caused by the mismatch between the instrument pads and the borehole diameter seriously affects the accuracy of fracture identification and formation continuity interpretation in marine oil and gas reservoirs. Existing inpainting methods struggle to reconstruct complex geological textures while maintaining structural continuity, particularly in balancing low-frequency formation morphology with high-frequency fracture details. To address this issue, this paper proposes an inpainting method using a dual-stream network based on the collaborative optimization of wavelet and spatial-channel convolution. By designing a texture-aware data prior algorithm, a high-quality training dataset with geological rationality is generated. A dual-stream encoder–decoder network architecture is adopted, and the wavelet transform convolution (WTConv) module is utilized to enhance the multi-scale perception ability of the generator, achieving a collaborative analysis of the low-frequency formation structure and high-frequency fracture details. Combined with the spatial channel convolution (SCConv) to enhance the feature fusion module, the cross-modal interaction between texture and structural features is optimized through a dynamic gating mechanism. Furthermore, a multi-objective loss function is introduced to constrain the semantic coherence and visual authenticity of image reconstruction. Experiments show that, in the inpainting indexes for Block X in the South China Sea, the mean absolute error (MAE), structural similarity index (SSIM), and peak signal-to-noise ratio (PSNR) of this method are 6.893, 0.779, and 19.087, respectively, which are significantly better than the improved filtersim, U-Net, and AOT-GAN methods. The correlation degree of the pixel distribution between the inpainted area and the original image reaches 0.921~0.997, verifying the precise matching of the low-frequency morphology and high-frequency details. In the inpainting of electrical imaging logging images across blocks, the applicability of the method is confirmed, effectively solving the interference of blank strips on the interpretation accuracy of marine oil and gas reservoirs. It provides an intelligent inpainting tool with geological interpretability for the electrical imaging logging interpretation of complex reservoirs, and has important engineering value for improving the efficiency of oil and gas exploration and development. Full article

Wastewater reinjection is an important measure for balancing the sustainable development of petroleum resources with environmental protection. However, the polymer-containing wastewater generated after polymer injection presents challenges such as reservoir damage and waterflooded zone identification in oilfields. To address this, this study systematically examined the impact of injection water with varying salinities on the flow characteristics and electrical responses of low-permeability reservoirs, based on rock-electrical and multiphase displacement experiments. Additionally, this study analyzed the factors influencing the damage to reservoirs during polymer-containing wastewater reinjection. Mass spectrometry, chemical compatibility tests, and SEM-based micro-characterization techniques were employed to reveal the micro-mechanisms of reservoir damage during the reinjection process, and corresponding protective measures were proposed. The results indicated the following: (1) The salinity of injected water significantly influences the electrical response characteristics of the reservoir. When low-salinity wastewater is injected, the resistivity–saturation curve exhibits a concave shape, whereas high-salinity wastewater results in a linear and monotonically increasing trend. (2) Significant changes were observed in the pore-throat radius distribution before and after displacement experiments. The average frequency of throats within the 0.5–2.5 µm range increased by 1.894%, while that for the 2.5–5.5 µm range decreased by 2.073%. In contrast, changes in the pore radius distribution were relatively minor. Both the experimental and characterization results suggest that pore-throat damage is the primary form of reservoir impairment following wastewater reinjection. (3) To mitigate formation damage during wastewater reinjection, a combined physical–chemical deblocking strategy was proposed. First, multi-stage precision filtration would be employed to remove suspended solids and oil contaminants. Then, a mildly acidic organic-acid-based compound would be used to inhibit the precipitation of metal ions and dissolve the in situ blockage within the core. This integrated approach would effectively alleviate the reservoir damage associated with wastewater reinjection. Full article

Aiming at the problem that conventional friction reducers used in fracturing cannot simultaneously possess properties such as temperature resistance, salt resistance, shear resistance, rapid dissolution, and low damage. Under the design concept of “medium-low molecular weight, salt-resistant functional monomer, supramolecular physical crosslinking aggregation, and enhanced chain mechanical strength”, acrylamide, sulfonic acid salt-resistant monomer 2-acrylamide-2-methylpropanesulfonic acid, hydrophobic association monomer, and rigid skeleton functional monomer acryloyl morpholine were introduced into the friction reducer molecular chain by free radical polymerization, and combined with the compound suspension technology to develop a new type of multi-functional viscous friction reducer suspension (SAMD), the comprehensive performance of SAMD was investigated. The results indicated that the critical micelle concentration of SAMD was 0.33 wt%, SAMD could be dissolved in 80,000 mg/L brine within 3.0 min, and the viscosity loss of 0.5 wt% SAMD solution was 24.1% after 10 min of dissolution in 80,000 mg/L brine compared with that in deionized water, the drag reduction rate of 0.1 wt% SAMD solution could exceed 70% at 120 °C and still maintained good drag reduction performance in brine with a salinity of 100,000 mg/L. After three cycles of 170 s⁻¹ and 1022 s⁻¹ variable shear, the SAMD solution restored viscosity quickly and exhibited good shear resistance. The Tan δ (a parameter characterizing the viscoelasticity of the system) of 1.0 wt% SAMD solution was 0.52, which showed a good sand-carrying capacity, and the proppant settling velocity in it could be as low as 0.147 mm/s at 120 °C, achieving the function of high drag reduction at low concentrations and strong sand transportation at high concentrations. The viscosity of 1.4 wt% SAMD was 95.5 mPa s after shearing for 120 min at 140 °C and at 170 s⁻¹. After breaking a gel, the SAMD solution system had a core permeability harm rate of less than 15%, while the SAMD solution also possessed the performance of enhancing oil recovery. Compared with common friction reducers, SAMD simultaneously possessed the properties of temperature resistance, salt resistance, shear resistance, rapid dissolution, low damage, and enhanced oil recovery. Therefore, the use of this multi-effect friction reducer is suitable for the development of unconventional oil reservoirs with a temperature lower than 140 °C and a salinity of less than 100,000 mg/L. Full article

The development of geo-energy resources, including oil, gas, and geothermal reservoirs, is being transformed through the creation of low-energy processes and innovative technologies. This Special Issue compiles cutting-edge research aimed at enhancing efficiency, sustainability, and recovery during geo-energy extraction. The published studies explore a diverse range of methodologies, such as the nanofluidic analysis of shale oil phase transitions, deep electrical resistivity tomography for geothermal exploration, and hybrid AI-driven production prediction models. Their key themes include hydraulic fracturing optimization, CO₂ injection dynamics, geothermal reservoir simulation, and competitive gas–water adsorption in ultra-deep reservoirs, and these studies combine advanced numerical modeling, experimental techniques, and field applications to address challenges in unconventional reservoirs, geothermal energy exploitation, and enhanced oil recovery. By bridging theoretical insights with practical engineering solutions, this Special Issue provides a comprehensive foundation for future innovations in low-energy geo-energy development. Full article

In fractured reservoirs, fractures serve as both water channeling and oil flow channels. Because of the impact of bottom water coning, the water channeling phenomenon becomes more problematic in the middle and late stages of reservoir development. Furthermore, residual oil is limited to small-scale fractures. In multi-scale fractures, the conventional pressure-bearing pattern of plugging agents is ambiguous. This results in low oil recovery, low sweep efficiency from water flooding, and low plugging agent application efficiency. Until now, the pressure-bearing patterns related to gel strength in multi-scale fractures have not been clear. In this paper, the gelation performances of temperature-resistant gel (TRG) samples with different elastic moduli were investigated. The elastic modulus of the TRG was normalized by the elastic modulus (G′) and viscosity modulus (G″). Subsequently, we carried out research on the bottom water pressure patterns of TRGs. This study revealed the pressure-bearing patterns of the TRGs under multi-scale fractures. A corresponding influence pattern chart was established, and the optimal surface function was fitted using the MATLAB nonlinear surface data fitting method. Finally, an application experiment for the characteristic chart was carried out. The plugging rate was evaluated based on the permeability reduction and pressure differential across the core samples before and after gel injection. Subsequently, a TRG with certain elastic moduli before and after plugging the core fracture node was selected from the chart. The elastic modulus of the TRG at the injection node prior to plugging was 14.29 Pa. The elastic modulus of the TRG at the injection node after plugging was 19.42 Pa. The experimental results showed that the TRG with an elastic modulus of 19.42 Pa effectively plugged the fractures and remained stable for over 90 days under a pressure differential of 53 KPa, resulting in a 58.7% improvement in oil recovery compared with water flooding. However, it was difficult for the TRG with an elastic modulus of 14.29 Pa to plug fractures efficiently, and it only enhanced the oil recovery by 15.2%. The primary aim of this work was to establish a quantitative and normalized evaluation method for temperature-resistant gels (TRGs) used in fractured reservoirs. By introducing a classification system based on the elastic modulus (G′) and correlating it with the fracture scale and plugging performance, this study bridges the gap between laboratory gel evaluations and field applications. The results provide practical design criteria and contribute to improving the efficiency and adaptability of gel plugging strategies under harsh reservoir conditions. Full article

Shale oil is abundant in geological reserves, but its recovery rate is low due to its unique characteristics of ultra-low porosity, ultra-low permeability, and high clay content. This study investigated the effect of mixed-charge surfactants (PSG) on enhanced oil recovery (EOR) in high-temperature shale reservoirs, building on our previous research. The results indicate that PSG not only has outstanding interfacial activity, anti-adsorption, and high-temperature resistance but can also alter the wettability of shale. After aging at 150 °C for one month, a 0.2% PSG solution exhibited minimal influence on the viscosity reduction and oil-washing properties but significantly altered the oil/water interfacial tension (IFT). Compared to field water, the 0.2% PSG solution enhances the static oil-washing efficiency by over 25.85% at 80 °C. Moreover, its imbibition recovery rate stands at 29.03%, in contrast to the mere 9.84% of field water. Because of the small adhesion work factor of the PSG solution system, it has a strong ability to improve shale wettability and reduce oil/water IFT, thereby improving shale oil recovery. This study provides the results of a laboratory experiment evaluation for enhancing shale oil recovery with surfactants. Furthermore, it holds significant potential for application in the single-well surfactant huff-n-puff process within shale reservoirs. Full article