Search Results (33)

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

To investigate the energy conduction behavior of polymer gel profile control and flooding in low-permeability reservoirs, a parallel dual-tube displacement experiment was conducted to simulate reservoirs with different permeability ratios. Injection schemes included constant rates from 0.40 to 1.20 mL/min and dynamic injection from 1.20 to 0.40 mL/min. Pressure monitoring and shunt analysis were used to evaluate profile control and recovery performance. The results show that polymer gel preferentially enters high-permeability layers, transmitting pressure more rapidly than in low-permeability zones. At 1.20 mL/min, pressure onset at 90 cm in the high-permeability layer occurs earlier than in the low-permeability layer. Higher injection rates accelerate pressure buildup. At 0.80 mL/min, permeability contrast is minimized, achieving a 22.96% recovery rate in low-permeability layers. The combination effect of 1.2–0.4 mL/min is the best in dynamic injection, with the difference in shunt ratio of 9.6% and the recovery rate of low permeability layer increased to 31.23%. Polymer gel improves oil recovery by blocking high-permeability channels, expanding the swept volume, and utilizing viscoelastic properties. Full article

This study presents the first quantitative comparison of catastrophic phase inversion behavior of water-in-oil emulsions stabilized by nanocrystalline cellulose (NCC) and molecular surfactants with different headgroup charge types: anionic (sodium dodecyl sulfate referred to as SDS), cationic (octadecyltrimethylammonium chloride referred to as OTAC), nonionic (C12–14 alcohol ethoxylate referred to as Alfonic), and zwitterionic (cetyl betaine referred to as Amphosol). By using conductivity measurements under controlled mixing and pendant drop tensiometry, this study shows that NCC markedly delays catastrophic phase inversion through interfacial jamming, whereas surfactant-stabilized systems exhibit concentration-dependent inversion driven by interfacial saturation. Specifically, NCC-stabilized emulsions exhibited a nonlinear increase in the critical aqueous phase volume fraction required for inversion, ranging from 0.253 (0 wt% NCC) to 0.545 (1.5 wt% NCC), consistent with enhanced resistance to inversion typically associated with the formation of rigid interfacial layers in Pickering emulsions. In contrast, surfactant-stabilized systems exhibited a concentration-dependent inversion trend with opposing effects. At low concentrations, limited interfacial coverage delayed inversion, while at higher concentrations, increased surfactant availability and interfacial saturation promoted earlier inversion and favored the formation of oil-in-water structures. Pendant drop tensiometry confirmed negligible surface activity for NCC, while all surfactants significantly lowered interfacial tension. Despite its weak surface activity, NCC imparted strong coalescence resistance above 0.2 wt%, attributed to steric stabilization. These findings establish distinct mechanisms for governing phase inversion in particle- versus surfactant-stabilized systems. To our knowledge, this is the first study to quantitively characterize the catastrophic phase inversion behavior of water-in-oil emulsions using NCC. This work supports the use of NCC as an effective stabilizer for emulsions with high internal phase volume. Full article

Reservoir heterogeneity, fluid property variations, and permeability contrasts across different geological layers result in significant disparities in water absorption capacities during oilfield development, often leading to premature water breakthrough, uneven sweep efficiency, and suboptimal waterflooding outcomes. The accurate determination of layer-specific water injection volumes is critical to addressing these challenges. This study focuses on a study area in China, employing comprehensive on-site investigations to evaluate the current state of layered water injection practices. The injection allocation strategy was optimized using a hybrid approach combining the splitting coefficient method and grey correlation analysis. Key challenges identified in the study area include severe reservoir heterogeneity, poor injection–production correspondence, rapid water cut escalation, and low recovery rates. Seven dominant influencing factors—the sedimentary microfacies coefficient, effective thickness, stimulation factor, well spacing, permeability, connectivity, and permeability range coefficient—were identified through grey correlation analysis. Field application of the proposed method across fourteen wells demonstrated significant improvements: a monthly oil production increase of 40 tons, a water production reduction of 399.24 m³/month, and a 2.45% decline in the water cut. The obtained results substantiate the method’s capability in resolving interlayer conflicts, optimizing oil recovery performance, and effectively controlling water channeling problems. Full article

The Polydimethylsiloxane (PDMS) SlipChip is a microfluidic platform enabling fluid manipulation without pumps or valves, simplifying operation and reducing reagent use. High-viscosity silicone oils (e.g., 5000–10,000 cSt) improve sealing but frequently block microfluidic channels, reducing usability. In contrast, low-viscosity oils (50–100 cSt) reduce blockages but may compromise sealing. This study addresses these challenges by optimizing the viscosity of silicone oil and the curing conditions of PDMS. Low-viscosity silicone oil (50 cSt) was identified as optimal, ensuring smooth slipping and reliable sealing without blockages. Curing conditions were also adjusted to balance adhesion and stiffness as follows: lower temperatures (50–60 °C) enhanced van der Waals adhesion, while higher temperatures (80 °C) increased stiffness. A mixed curing approach (80 °C for the top layer and 60 °C for the bottom layer) further improved performance. Biocompatibility testing using human osteosarcoma cells demonstrated minimal cytotoxicity with 50 cSt oil, supporting cell viability (95%) comparable to traditional multiwell plates. These findings provide practical guidelines for fabricating reliable and biocompatible SlipChips. Full article

Tight sandstone reservoirs are characterized by fine-grained rock particles, a high clay content, and a complex interplay between the electrical properties and gas content. These factors contribute to low-contrast reservoirs, where the logging responses of the gas and water layers are similar, resulting in traditional logging interpretation charts exhibiting a low accuracy in the fluid-type classification. This inadequacy fails to meet the fluid identification needs of the study area’s reservoirs and severely restricts the exploration and development of unconventional oil and gas resources. To address this challenge, this study proposes a fluid identification method based on Bayesian-optimized Support Vector Machine (SVM) to enhance the accuracy and efficiency of the fluid identification in low-contrast reservoirs. Firstly, through a sensitivity analysis of the logging responses, sensitive logging parameters such as the natural gamma, compensated density, compensated neutron, and compensated sonic logs are selected as input data for the model. Subsequently, Bayesian optimization is employed to automatically search for the optimal combination of hyperparameters for the SVM model. Finally, an SVM model is established using the optimized hyperparameters to classify and identify the following four fluid types: water layers, gas layers, gas–water layers, and dry layers. The proposed method is applied to fluid identification in the study area, and comparative experiments are conducted with the K-Nearest Neighbor (KNN), Random Forest (RF), and AdaBoost models. The classification performance of each model is systematically evaluated using metrics such as the accuracy, recall, and F1-score. The experimental results indicate that the SVM model outperforms the other models in fluid identification, achieving an average accuracy of 91.41%. This represents improvements of 16.94%, 4.39%, and 8.30% over the KNN, RF, and AdaBoost models, respectively. These findings validate the superiority of the SVM model for fluid identification in the study area and provide an efficient and feasible solution for fluid identification in tight sandstone reservoirs. Full article

Offshore low-permeability thin interbedded reservoirs contain significant oil reserves and are crucial for future development. However, due to the high cost and operational challenges associated with offshore fracturing, large-scale fracturing common in onshore fields is uneconomical. Furthermore, offshore low-permeability reservoirs often have sparse well placement and wide well spacing, in contrast to onshore low-permeability fields, which leads to low recovery. Additionally, there is a lack of comprehensive theory on optimizing the well patterns and fracture networks to maximize net income, highlighting the need for further research. This study tackles these issues in a low-permeability thin interbedded reservoir in the Bozhong Oilfield by using reservoir numerical simulation. First, fracture parameters, including fracture half-length and conductivity, are optimized for different well patterns. Subsequently, well pattern optimization is conducted under fractured conditions, targeting maximum net income under various conditions. The results indicate that when fractures are confined to a single reservoir layer and the main reservoir layer accounts for less than 36% of the development section, fractured directional well patterns yield a higher net income. Conversely, when fractures penetrate all reservoir layers, fractured horizontal wells with closer fracture spacing a higher number of fractures are the most profitable option, particularly in offshore fields with large well spacing. The findings provide critical insights into optimizing well patterns and fracture network designs for offshore low-permeability thin interbedded reservoirs. Full article

Stromatolites, distinctive fossil records within Precambrian strata, are essential for investigating the depositional environments of early Earth and the geological settings conducive to hydrocarbon formation. The Luonan area is located in Shaanxi Province, China, where a large number of stromatolites have been discovered within the Mesoproterozoic Erathem, providing new perspectives on paleoenvironment and reservoir spaces. This study analyzes the morphology of stromatolites, associated microorganisms, mineralogy, and cathodoluminescence from the carbonate rocks of the Jixian System. Carbon and oxygen isotope analyses help reconstruct paleosalinity and climate, enhancing understanding of their petroleum geological significance. Combining carbon and oxygen isotope analysis with the fine observation and description of stromatolite can better reconstruct the paleoenvironmental features of the Mesoproterozoic Era. The results indicated a narrow range of carbon isotope values (δ¹³C: −5.81‰ to −2.43‰; mean: −4.03‰) and oxygen isotope values (δ¹⁸O: −9.06‰ to −5.64‰). The Longjiayuan Formation is characterized by high CaO and MgO content, with low SiO₂ and minimal terrigenous input, in contrast with the Fengjiawan Formation, which exhibits elevated SiO₂ and greater terrigenous material. The Luonan stromatolites display prominent rhythmic laminations, primarily composed of dolomite, indicating a potential for hydrocarbon source rocks. Stromatolite morphologies, including layered, columnar, and wavy forms, reflect varied depositional microfacies. The alternating bright and dark laminae, rich in CaO and CO₂ but differing in Ca²⁺ and Mg²⁺ concentrations, signify seasonal growth cycles. These Mesoproterozoic stromatolites developed in a warm, humid, and stable climatic regime, within a marine anoxic-to-suboxic setting, typically in intertidal or supratidal zones with low hydrodynamic energy. In the southern margin of the North China Craton, stromatolites from the Mesoproterozoic Era are extensively developed and exhibit distinct characteristics. Due to the biogenic alteration of stromatolites, the porosity of the rock increased. These stromatolites have altered the physical properties of the host rocks to some extent, suggesting the possibility of becoming effective hydrocarbon reservoirs. This has significant implications for deep oil and gas exploration, providing valuable guidance for future prospecting efforts. Full article

Acid-fracturing technology has been applied to form pathways between deep oil/gas resources and oil production pipelines. The acid fracturing fluid is required to have special slow-release performance, with no acidity at low temperatures, while steadily generating acid at high temperatures underground. At present, commercial acid systems in oilfields present problems such as the uncontrollable release effect, high costs, and significant pollution. In this research, we designed an innovative chloroformate material and investigated the release of the acid at various temperatures. This new chloroformate material reacts slowly with water at room temperature, and can completely react with water to form hydrochloric acid at high temperatures, without residual organic chlorine and other harmful substances; thus, it is suitable for use as an acid agent in oilfields. To isolate the acid-release core material from the outer water phase, we encapsulated the former with various materials, such as cross-linked polyacrylate or polystyrene, to obtain microcapsules. By slowly breaking and degrading the shell layer at a high temperature, the goal of no acid being released at low temperatures with slow acid generation at a high temperature was achieved. The microcapsules were prepared using radical polymerization and the phase separation method. Furthermore, scanning electron microscopy, differential scanning calorimetry, chemical titration analysis, and other methods were used to characterize the structure and the sustained acid release of microcapsules. The results of thermogravimetry and other experiments showed that the prepared microcapsules successfully coated the chloroformate material. In contrast to the bare material, the slow-release performance of the microcapsules was significantly improved, and the continuous acid generating time was able to reach more than 10 h. Under optimum conditions, microcapsules with a uniform particle size with a sustained-release acid core were prepared, and the encapsulation efficiency reached up to 60%. Compared with traditional acid-release systems, the new system prepared in this study has better acid-release performance at high temperatures, while the product is both clean and convenient to use. Multiple important parameters, such as microcapsule particle size, can also be controlled by varying the experimental conditions to meet the needs of different oil/gas extraction environments. In summary, we prepared a promising new and efficient slow-release acid generation system, which has unique practical significance for optimizing current oilfield acid-fracturing technology. Full article

Hydraulic fracturing technology is vital for the efficient extraction of oil and gas from low-permeability tight sandstone reservoirs.Taking the central Bohai oilfield in China as an example, these fields are typically composed of thinly interbedded tight sandstone, characterized by low permeability and significant lithological heterogeneity between layers. Fractures may either be confined, limiting vertical growth and reducing production, or overextend into water-bearing zones, causing contamination and compromising reservoir integrity. Therefore, predicting vertical fracture propagation during field fracturing operations is critical for efficient resource extraction.However, there is still a lack of comprehensive understanding of the mechanisms governing vertical fracture growth offshore.This paper applies numerical simulations based on the finite element method to elucidate the interlayer fracture propagation behavior in low-permeability tight sandstone reservoirs. A fracture propagation model for thin interlayered tight sandstone formations is constructed, and the effects of various factors on hydraulic fracture propagation are systematically analyzed, including geological factors such as interlayer stress contrast, thickness, and differences in elastic modulus, as well as operational parameters including fracturing fluid viscosity and injection rate. This study clarifies the cross-layer propagation patterns of hydraulic fractures under the influence of multiple factors and yields a comprehensive prediction chart for fracture propagation thickness under the combination of complex factors. The results of this research can provide theoretical support for the design of reservoir stimulation operations in low-permeability tight sandstone oilfields. Full article

The fat covered by fat globule membrane is scattered in a water phase rich in lactose and milky protein, forming the original emulsion structure of milk. In order to develop low-fat milk products with good performance or dairy products with nutritional reinforcement, the original emulsion structure of milk can be restructured. According to the type of lipid and emulsion structure in milk, the remolded emulsion structure can be divided into three types: restructured single emulsion structure, mixed emulsion structure, and double emulsion structure. The restructured single emulsion structure refers to the introduction of another kind of lipid to skim milk, and the mixed emulsion structure refers to adding another type of oil or oil-in-water (O/W) emulsion to milk containing certain levels of milk fat, whose final emulsion structure is still O/W emulsion. In contrast, the double emulsion structure of milk is a more complicated structural remodeling method, which is usually performed by introducing W/O emulsion into skim milk (W₂) to obtain milk containing (water-in-oil-in-water) W₁/O/W₂ emulsion structure in order to encapsulate more diverse nutrients. Causal statistical analysis was used in this review, based on previous studies on remodeling the emulsion structures in milk and its gelling products. In addition, some common processing technologies (including heat treatment, high-pressure treatment, homogenization, ultrasonic treatment, micro-fluidization, freezing and membrane emulsification) may also have a certain impact on the microstructure and properties of milk and its gelling products with four different emulsion structures. These processing technologies can change the size of the dispersed phase of milk, the composition and structure of the interfacial layer, and the composition and morphology of the aqueous phase substance, so as to regulate the shelf-life, stability, and sensory properties of the final milk products. This research on the restructuring of the emulsion structure of milk is not only a cutting-edge topic in the field of food science, but also a powerful driving force in promoting the transformation and upgrading of the dairy industry to achieve high-quality and multi-functional dairy products, in order to meet the diversified needs of consumers for health and taste. Full article

The Weixinan Sag in the Beibuwan Basin is rich in shale oil resources. However, the reservoirs exhibit rapid phase changes, strong compartmentalization, thin individual layers, and high-frequency vertical variations in the thin interbedded sandstone and mudstone. These factors can restrict the height of hydraulic fracture propagation. Additionally, the low-porosity and low-permeability shale oil reservoirs face challenges such as low production rates and rapid decline. To address these issues, the Plannar3D full 3D fracturing model was used to simulate hydraulic fracture propagation and to study the main controlling factors for fracture propagation in the second member of the Liushagang Formation. Based on the concept of geological–engineering integration, a sweet spot evaluation was conducted to identify reservoirs with relatively better brittleness, reservoir properties, and oil content as the fracturing targets for horizontal wells. The UFM model was then applied to optimize fracturing parameters. This study indicates that the matrix-type oil shale has a high clay mineral content, resulting in a low Young’s modulus and poor brittleness. This makes hydraulic fracture propagation difficult and leads to less effective reservoir stimulation. In contrast, hydraulic fractures propagate more easily in high-brittleness interlayer-type oil shale. Therefore, it is recommended to prioritize the extraction of shale oil from interlayer-type oil shale reservoirs. The difference in interlayer stress is identified as the primary controlling factor for cross-layer fracture propagation in the study area. Based on the concept of geological–engineering integration, a sweet spot evaluation standard was established for the second member of the Liushagang Formation, considering both reservoir quality and engineering quality. Four sweet spot zones of interlayer-type oil shale reservoirs were identified according to this evaluation standard. To achieve uniform fracture initiation, a differentiated segment and cluster design was implemented for certain high-angle sections of well WZ11-6-5d. Interlayer-type oil shale was selected as the fracturing target, and the UFM was used for hydraulic fracture propagation simulation. Fracturing parameters were optimized with a focus on hydraulic fracture characteristics and the estimated ultimate recovery (EUR). The optimization results were as follows: a single-stage length of 50 m, cluster spacing of 15 m, pump injection rate of 10 m³/min, fluid intensity of 25 m³/m, and proppant intensity of 3.5 t/m. The application of these optimized fracturing parameters in field operations resulted in successful fracturing and the achievement of industrial oil flow. Full article

Yingxiongling shale oil is considered a critical area for future crude oil production in the Qaidam Basin. However, the unique features of the Yingxiongling area, such as extraordinary thickness, hybrid sedimentary, and extensive reformation, are faced with several challenges, including an unclear understanding of the main controlling factors for hydraulic fracturing propagation, difficulties in selecting engineering sweet layers, and difficulties in optimizing the corresponding fracturing schemes, which restrict the effective development of production. This study focuses on mixed fine-grained sedimentary rocks, employing a high-resolution integrated three-dimensional geological-geomechanical model to simulate fracture propagation. By combining laboratory core experiments, a holistic investigation of the controlling factors was conducted, revealing that hydraulic fracture propagation in mixed fine-grained sedimentary rocks is mainly influenced by rock brittleness, natural fractures, stress, varying lithologies, and fracturing parameters. A comprehensive compressibility evaluation standard was established, considering brittleness, stress contrast, and natural fracture density, with weights of 0.3, 0.23, and 0.47. In light of the high brittleness, substantial interlayer stress differences, and localized developing natural microfractures in the Yingxiongling mixed fine-grained sedimentary rock reservoir, this study examined the influence of various construction parameters on the propagation of hydraulic fractures and optimized these parameters accordingly. Based on the practical application in the field, a “three-stage” stimulation strategy was proposed, which involves using high-viscosity fluid in the front to create the main fracture, low-viscosity fluid with sand-laden slugs to create volume fractures, and continuous high-viscosity fluid carried sand to maintain the conductivity of the fracture network. The resulting oil and gas seepage area corresponding to the stimulated reservoir volume (SRV) matched the actual well spacing of 500 m, achieving the effect of full utilization. The understanding of the controlling factors for fracture expansion, the compressibility evaluation standard, and the main process technology developed in this study effectively guide the optimization of transformation programs for mixed fine-grained sedimentary rocks. Full article

Despite the abundance of shale-oil and tight-oil reserves in the Fengcheng Formation within the Mahu Sag, exploration and development efforts for both types of reservoir are still in their early stages. A comprehensive examination and comparison of the pore structures of these reservoirs can establish rational classification and evaluation criteria. However, there is a dearth of comparative analyses focusing on the pore structures of shale-oil and tight-oil reservoirs within the Fengcheng Formation. This study addresses this gap by systematically analyzing and comparing the pore structures of these reservoirs using various techniques such as X-ray diffraction (XRD), scanning electron microscopy (SEM), low-temperature nitrogen adsorption, and mercury intrusion capillary pressure experiments (MICP). The results show that the shale oil within the Fengcheng Formation exhibits a higher content of carbonic acid compared to the tight-oil samples. Furthermore, it demonstrates smaller displacement pressure and median pressure, a larger sorting coefficient, and superior permeability in contrast to tight oil. Notably, the shale oil within the Fengcheng Formation is characterized by abundant striated layer structures and micro-fractures, which significantly contribute to the microstructural disparities between shale-oil and tight-oil reservoirs. These differences in microstructures between shale oil and tight oil within the Fengcheng Formation in the Mahu Sag region delineate distinct criteria for evaluating sweet spots in shale-oil and tight-oil reservoirs. Full article

Increasing oil production is crucial for multilayer co-production. When there are significant differences in the permeability of each layer, an interlayer contradiction arises that can impact the recovery efficiency. After a number of tests and the establishment of a mathematical model, the effects of permeability contrast on oil production for water flooding were revealed. In the meantime, the developed mathematical model was solved using the Buckley–Lever seepage equation. Ultimately, the accuracy of the established model was confirmed by comparing the simulated outcomes of the mathematical model with the experimental results. The findings indicate that when permeability contrast increases, the production ratio of the high-permeability layer will improve. This is primarily due to the low-permeability layer’s production contribution rate decreasing. The accuracy of the established model is ensured by an error of less than 5% between the results of the experiment and the simulation. When the permeability contrast is less than three, the low-permeability layer can be effectively used for three-layer commingled production. However, when the permeability contrast exceeds six, the production coefficient of the low-permeability layer will be less than 5%, which has a significant impact on the layer’s development. Full article