Search Results (67)

The in situ emulsification synergistic self-profile control system has wide application prospects for efficient development on offshore oil reservoirs. During water flooding in Bohai heavy oil reservoirs, random emulsification occurs with superimposed Jamin effects. Effectively utilizing this phenomenon can enhance the efficient development of offshore oilfields. This study addresses the challenges hindering water flooding development in offshore oilfields by investigating the emulsification mechanism and key influencing factors based on oil–water emulsion characteristics, thereby proposing a novel in situ emulsification flooding method. Based on a fundamental analysis of oil–water properties, key factors affecting emulsion stability were examined. Core flooding experiments clarified the impact of spontaneous oil–water emulsification on water flooding recovery. Two-dimensional T1–T2 NMR spectroscopy was employed to detect pure fluid components, innovating the method for distinguishing oil–water distribution during flooding and revealing the characteristics of in situ emulsification interactions. The results indicate that emulsions formed between crude oil and formation water under varying rheometer rotational speeds (500–2500 r/min), water cuts (30–80%), and emulsification temperatures (40–85 °C) are all water-in-oil (W/O) type. Emulsion viscosity exhibits a positive correlation with shear rate, with droplet sizes primarily ranging between 2 and 7 μm and a viscosity amplification factor up to 25.8. Emulsion stability deteriorates with increasing water cut and temperature. Prolonged shearing initially increases viscosity until stabilization. In low-permeability cores, spontaneous oil–water emulsification occurs, yielding a recovery factor of only 30%. For medium- and high-permeability cores (water cuts of 80% and 50%, respectively), recovery factors increased by 9.7% and 12%. The in situ generation of micron-scale emulsions in porous media achieved a recovery factor of approximately 50%, demonstrating significantly enhanced oil recovery (EOR) potential. During emulsification flooding, the system emulsifies oil at pore walls, intensifying water–wall interactions and stripping wall-adhered oil, leading to increased T2 signal intensity and reduced relaxation time. Oil–wall interactions and collision frequencies are lower than those of water, which appears in high-relaxation regions (T1/T2 > 5). The two-dimensional NMR spectrum clearly distinguishes oil and water distributions. Full article

Wide-range electric submersible centrifugal pumps (ESPs) are critical for offshore oilfields but suffer from narrow high-efficiency ranges and frictional losses under dynamic reservoir conditions. This study introduces bio-inspired dimple-type non-smooth surfaces on impeller blades to enhance hydraulic performance. A combined numerical-experimental approach was employed: a 3D CFD model with the k-ω turbulence model analyzed oil–water flow (1:9 ratio) to identify optimal dimple placement, while parametric studies tested diameters (0.6–1.2 mm). Experimental validation used 3D-printed prototypes. Results revealed that dimples on the pressure surface trailing edge reduced boundary layer separation, achieving a 12.98% head gain and 8.55% efficiency improvement at 150 m³/d in simulations, with experimental tests showing an 11.5% head increase and 4.6% efficiency gain at 130 m³/d. The optimal dimple diameter (0.9 mm, 2% of blade chord) balanced performance and manufacturability, demonstrating that bio-inspired surfaces improve ESP efficiency. This work provides practical guidelines for deploying drag reduction technologies in petroleum engineering, with a future focus on wear resistance in abrasive flows. Full article

The Oligocene Dongying Formation beach-bar system, widely distributed in the HHK Depression of the Bohai Bay Basin, constitutes a key target for mid-deep hydrocarbon exploration, though its provenance remains controversial due to complex peripheral source terrains. To address this, we developed an integrated methodology combining LA-ICP-MS zircon U-Pb dating with whole-rock rare earth element (REE) analysis, facilitating provenance studies in areas with limited drilling and heavy mineral data. Analysis of 849 high-concordance zircons (concordance >90%) from 12 samples across 5 wells revealed that Geochemical homogeneity is evidenced by strongly consistent moving-average trendlines of detrital zircon U-Pb ages among the southern/northern provenances and the central uplift zone, complemented by uniform REE patterns characterized by HREE (Gd-Lu) enrichment and LREE depletion; geochemical disparities manifest as dual dominant age peaks (500–1000 Ma and 1800–3100 Ma) in the southern provenance and central uplift samples, contrasting with three distinct peaks (65–135 Ma, 500–1000 Ma, and 1800–3100 Ma) in the northern provenance; spatial quantification via multidimensional scaling (MDS) demonstrates closer affinity between the southern provenance and central uplift (d_ij = 4.472) than to the northern provenance (d_ij = 6.708). Collectively, these results confirm a dual (north–south) provenance system for the central uplift beach-bar deposits, with the southern provenance dominant and the northern acting as a subsidiary source. This work establishes a dual-provenance beach-bar model, providing a universal theoretical and technical framework for provenance analysis in hydrocarbon exploration within analogous settings. Full article

Multi-stage fractured horizontal wells (MSFHWs) represent a crucial development approach for low-permeability reservoirs, where accurate productivity prediction is essential for production operations. However, existing models suffer from limitations such as inadequate characterization of complex flow mechanisms within the reservoir or computational complexity. This study subdivides the flow process into three segments: matrix, fracture, and wellbore. By employing discretization concepts, potential distribution theory, and the principle of potential superposition, a productivity prediction model tailored for MSFHWs in low-permeability reservoirs is established. Moreover, this model provides a clearer characterization of fluid seepage processes during horizontal well production, which aligns more closely with the actual production process. Validated against actual production data from an offshore oilfield and benchmarked against classical models, the proposed model demonstrates satisfactory accuracy and reliability. Sensitivity analysis reveals that a lower Threshold Pressure Gradient (TPG) corresponds to higher productivity; a production pressure differential of 10 MPa yields an average increase of 22.41 m³/d in overall daily oil production compared to 5 MPa, concurrently reducing the overall production decline rate by 26.59% on average. Larger stress-sensitive coefficients lead to reduced production, with the fracture stress-sensitive coefficient exerting a more significant influence; for an equivalent increment, the matrix stress-sensitive coefficient causes a production decrease of 1.92 m³/d (a 4.32% decline), while the fracture stress-sensitive coefficient results in a decrease of 4.87 m³/d (a 20.93% decline). Increased fracture half-length and number enhance production, with an initial productivity increase of 21.61% (gradually diminishing to 7.1%) for longer fracture half-lengths and 24.63% (gradually diminishing to 5.22%) for more fractures; optimal critical values exist for both parameters. Full article

The development of inter-well channeling pathways has become a major challenge restricting the effectiveness of the thermal recovery process for heavy oil reservoirs, which leads to non-uniform sweep and reduced oil recovery. This is especially true for the characteristics of the higher injection–production intensity in offshore operations, making the issue more prominent. In this study, a quick and widely applicable approach is proposed for channeling identification, utilizing the static reservoir parameters and injection–production performance. The results show that the cumulative injection–production pressure differential (CIPPD) over the cumulative water equivalent (CWE) exhibits a linear relationship when connectivity exists between the injection and production wells. Thereafter, the seepage resistance could be analyzed quantitatively by the slope of the linear relationship during the steam injection process. Simultaneously, a channeling identification chart could be obtained based on the data of injection–production performance, dividing the steam flooding process into three different stages, including the energy recharge zone, interference zone, and channeling zone. Then, the established channeling identification chart is applied to injection–production data from two typical wells in the Bohai oilfield. From the obtained channeling identification chart, it is shown that Well X1 exhibits no channeling, while Well X2 exhibited channeling in the late stage of the steam flooding process. These findings are validated against the field performance (i.e., the liquid rate, water cut, flowing temperature, and flowing pressure) to confirm the accuracy. The channeling identification approach in this paper provides a guide for operational adjustments to improve the effect of the thermal recovery process in the field. Full article

Geological storage of CO₂ in offshore deep saline aquifers is widely recognized as an effective strategy for large-scale carbon emission reduction. This study aims to assess the mechanical integrity and storage efficiency of reservoirs using a multi-layer CO₂ injection method in the Enping 15-1 Oilfield CO₂ storage project which is the China’s first offshore carbon capture, utilization, and storage (CCUS) demonstration. A coupled Hydro–Mechanical (H–M) model is constructed using the TOUGH-FLAC simulator to simulate a 10-year CO₂ injection scenario, incorporating six vertically distributed reservoir layers. A sensitivity analysis of 14 key geological and geomechanical parameters is performed to identify the dominant factors influencing injection safety and storage capacity. The results show that a total injection rate of 30 kg/s can be sustained over a 10-year period without exceeding mechanical failure thresholds. Reservoirs 3 and 4 exhibit the greatest lateral CO₂ migration distances over the 10-year injection period, indicating that they are the most suitable target layers for CO₂ storage. The sensitivity analysis further reveals that the permeability of the reservoirs and the friction angle of the reservoirs and caprocks are the most critical parameters governing injection performance and mechanical stability. Full article

Hydraulic fracturing-assisted oil displacement (HFAOD) can improve the productivity of offshore low-permeability reservoirs, but challenges such as rapid productivity decline, difficulty in controlling fracture height, and unclear influence of geological and operational factors on key parameters of HFAOD persist. This study establishes a fluid-solid coupling model for HFAOD and verifies its accuracy with field data. It clarifies the laws of HFAOD fracture propagation and fluid infiltration, conducts sensitivity analyses to identify dominant factors affecting fracture propagation and fluid infiltration, and achieves quantitative characterization and rapid prediction of fracture half-length and infiltration radius. The results indicate that the HFAOD fluid undergoes simultaneous infiltration during fracture propagation. In the initial stage of HFAOD, the fluid primarily contributes to fracture creation with limited infiltration, while in the middle to late stages, fracture propagation diminishes, and the infiltration radius expands significantly. The dominant controlling factors affecting HFAOD fracture propagation are reservoir thickness and cumulative injection volume; the dominant controlling factors affecting HFAOD fluid infiltration are permeability and formation pressure coefficient before HFAOD, which should be given special attention on site. This study quantifies the relationships between HFAOD key parameters (fracture half-length and infiltration radius) and their dominant controlling factors and establishes a mathematical model for a rapid prediction of these parameters. The research results provide a theoretical basis for optimizing HFAOD designs in offshore low-permeability reservoirs. Full article

A numerical analysis model for sand-mudstone interbedded fracturing based on field application in South China is presented in this paper. The proposed model can analyze the influence laws of different longitudinal lithology changes, stress difference changes, different interlayer positions, and fracturing fluid construction parameters on fracture characteristics. Based on the study of fracture characteristics of low-modulus mudstone, a set of layered stress loading experimental devices was independently designed and developed. Experimental analysis shows that the stress difference has a limited limiting effect on the interlayer propagation of hydraulic fracturing fractures in the Weizhou Formation, and the fracture height is prone to interlayer propagation. The injection of high-rate and high-viscosity fracturing fluid has a significant impact on the hydraulic fracture surface penetration. Numerical simulation analysis shows that the smaller the elastic modulus of the mudstone interlayer and the lower the minimum horizontal principal stress compared to the sandstone layer, the more favorable it is for fracture propagation. Field application showed that the highest injection rate of the fracturing pump in well A was 7 m³/min for south-west Weizhou oilfield shale oil. The interpretation results of the acoustic logging after fracturing showed obvious response characteristics of the formation fractures, and the farthest detection fracture response well distance was 12 m, indicating a good fracturing transformation effect and providing technical support for subsequent offshore shale oil fracturing construction. Full article

Electric submersible pumps (ESPs) are crucial equipment in offshore oilfield production. Due to their complex structure and the variable geological environments in which they work, ESPs are prone to a wide range of complex faults. Existing fault diagnosis models for ESP wells face several issues, including high subjective dependence, large sample data requirements, and poor adaptability to different geological environments. These issues lead to relatively low accuracy in ESP well fault diagnosis. To address these challenges, this paper integrates the mechanistic knowledge of ESP wells with their working parameters to construct a fault symptom inference model for ESP wells. A fault diagnosis model for ESP wells is formed by combining deep learning with an expert rule-based fault diagnosis method. The two models are connected in series to construct a mechanism knowledge-integrated ESP fault diagnosis model (MK-ESPFDM), achieving real-time and accurate diagnosis of faults in ESP wells. A series of experiments demonstrate that the proposed algorithm strategy can effectively improve the diagnostic accuracy of the model. It also reduces human subjectivity and enhances the model’s adaptability to different faults and geological environments. The research presented in this paper has reached a high level in the field of ESP well fault diagnosis. Full article

The Bohai SZ36-1 oilfield, the largest offshore oilfield in China, features a high-porosity, high-permeability reservoir with significant heterogeneity and permeability variations. After extended water injection, the reservoir’s pore structure evolved, increasing heterogeneity and reducing the effectiveness of traditional production methods. To address these issues, this study introduces an intelligent diversion and balanced unblocking technology, using a temperature-controlled diversion system to block dominant flow channels and ensure even distribution of treatment fluids while maintaining reservoir integrity. The technology’s scientific validity and feasibility were confirmed through extensive testing. Results show that the diversion system offers excellent injectability, with controllable solidification time, phase change temperature, and strong compatibility, allowing for a “liquid–solid–liquid” phase transition in the reservoir. The technology also demonstrates high plugging strength, rapid plugging rate, significant diversion effects, and moderate injection intensity, all meeting construction requirements. Full article

Fuzzy-ball fluids have emerged as a novel class of chemical sealaplugging materials with significant potential for enhancing both traditional oilfield operations and clean energy technologies. They are characterized by unique viscoelastic properties, plugging, self-adapting capabilities, and the ability to regulate multi-phase fluid flow under extreme subsurface conditions. In oilfield applications, fuzzy-ball fluids offer solutions for drilling, hydraulic fracturing, workover operations, and enhanced oil recovery in shallow, deep, and offshore reservoirs. In clean energy fields such as hydrogen storage, carbon capture, utilization, and storage, and geothermal energy, they show promise in improving energy efficiency, storage security, and environmental sustainability. This review explores the fundamental principles and mechanisms behind fuzzy-ball fluids, examines their field applications in the oil and gas industry, and investigates their potential in emerging clean energy technologies. This study also identifies key challenges, including material stability, economic viability, and environmental impact, which must be addressed to ensure the successful deployment of fuzzy-ball fluids. Furthermore, we outline future research directions, emphasizing material optimization, large-scale field trials, environmental impact assessments, and interdisciplinary collaboration to accelerate the commercialization of fuzzy-ball fluid technologies. By addressing these challenges, fuzzy-ball fluids could play a transformative role in both conventional and clean energy fields, contributing to sustainable and efficient energy solutions. Full article

Polymer flooding has been gradually applied in Chinese offshore oilfields to enhance oil recovery (EOR). Injectivity loss during polymer flooding is a common issue that could cause lower displacement speed and efficiency, and eventually compromise the polymer flooding result. This paper presents a case study of a Chinese offshore field where injectivity loss issues were encountered in the polymer flooding project. A series of measures are applied to enhance the injectivity. The injectivity enhancement strategies are proposed and conducted from three main aspects, namely, (1) surface polymer fluid preparation; (2) downhole wellbore stimulation; and (3) reservoir–polymer compatibility, respectively. For the surface polymer fluid preparation, a series of sieve flow tests are conducted to obtain the optimal mesh size to improve the polymer fluid preparation quality and reduce the amount of “fish eyes”. The downhole wellbore stimulations involve oxidization-associated acidizing treatment and re-perforation. Polymer–reservoir compatibility tests are conducted to optimize the molecular weight (MW). Regarding the surface measures, the optimal filtration sieve mesh number is 200, which could reduce fish eyes to a desirable level without causing mesh plugging. After mesh refinement, the average injection pressure of the twelve injection wells decreases by 0.5 MPa. For the downhole stimulations, acidizing treatment are applied to six injection wells, which decreases the injection pressures by 6 to 7 MPa. For Well A, where acidizing does not work, the re-perforation measure is used and enhances the injectivity by 300%. Moreover, the laboratory and field polymer–reservoir compatibility tests show that the optimal polymer molecular weight (MW) is sixteen million. Proposed strategies applied from the surface, downhole, and reservoir aspects could be used to resolve different levels of injectivity loss, which could provide guidance for future offshore polymer projects. Full article

The conventional polymer gel has high initial viscosity and short gelation time, making it difficult to meet the requirements of deep profile control in offshore reservoirs with large well spacing and strong heterogeneity. This paper evaluates the performance and core plugging capacity of novel functional polymer gels and microspheres to determine the applicability of core permeability ranges. On the heterogeneous core designed based on the reservoir characteristics of Block B oilfield, optimization was conducted separately for the formulation, dosage, and slug combinations of the polymer gel/microsphere. Finally, oil displacement experiments using polymer and microsphere combinations were conducted on vertically and planar heterogeneous cores to simulate reservoir development effects. The experimental results show the novel functional polymer gel exhibits slow gelation with high gel strength, with viscosity rapidly increasing four days after aging, ultimately reaching a gel strength of 74,500 mPa·s. The novel functional polymer gel and polymer microsphere can effectively plug cores with permeabilities below 6000 mD and 2000 mD, respectively. For heterogeneous cores with an average permeability of 1000 mD, the optimal polymer microsphere has a concentration of 4000 mg/L and a slug size of 0.3 PV; for heterogeneous cores with an average permeability of 4000 mD, the optimal functional polymer gel has a concentration of 7500 mg/L and a slug size of 0.1 PV. In simulations of vertically and planarly heterogeneous reservoirs, the application of polymer agent increases the oil recovery factor by 53% and 38.7% compared to water flooding. This realizes the gradual and full utilization of layers with high, medium, and low permeability. Full article

Offshore multilayer sandstone reservoirs are characterized by complex vertical alternating thick and thin layers, resulting in significant heterogeneity. Traditional productivity evaluation methods often fail to effectively represent the dynamic production patterns of individual wells. This study focuses on the S oilfield offshore (Bohai Bay, China) as a case study. By considering the structural characteristics of thin layers and sand bodies, the reservoir is classified into four types: strong continuous thick layers, weak continuous thick layers, alternating thick–thin layers, and weak continuous thin layers. Based on this classification, a multilayer perceptron classification model based on graph attention neural networks is developed. The model achieves a high classification accuracy of 96.6% by mining the interdependencies between 14 input parameters. Further, by fitting the relationship between interlayer interference coefficients and water cuts for typical wells, a dynamic variation diagnosis plot for interlayer interference coefficients under different reservoir combinations is established. Additionally, a calculation method for the oil productivity index based on reservoir combination patterns is proposed. The method’s effectiveness was validated through field application, where the results significantly improved the correlation between the water-free oil productivity index and flow coefficient, with calculation errors of less than 10% compared to measured values. Full article

Fracturing flooding is a new technology that combines traditional conventional water drive, chemical drive, and hydraulic fracturing technologies and injects water under proximity fracture pressure to increase the wave area. It is currently applied in onshore low-permeability oilfields with good results, but the research on the design method of fracturing flooding in offshore low-permeability reservoirs is still lacking. Numerical simulation studies of well fracturing flooding are needed to optimize the key parameters of fracturing flooding development. This study simulates the real-time fracture dynamic expansion process of micro-level fracture expansion for hydraulic fracturing, combines it with a numerical simulation of well pressure-driving, and finally optimizes the parameters of hydraulic flooding. By studying the fracture expansion law, this study determined that the total amount of injection volume had a large influence on both fracture half-length and inflow capacity; the larger the injection rate, the larger the fracture half-length, but the inflow capacity was basically unchanged. It was also found that multiple rounds of fracturing flooding had no effect on fracture morphology or length. In studying the key fracturing flooding parameters in oil wells, it was concluded that the higher the total injection amount, the higher the oil increase in fracturing flooding and the wider the wave area of pressure-driving. Moreover, the higher the displacement, the higher the pressure near the bottom of the well, but there was little difference in the spreading area; in addition, the longer the well shut-in time, the higher the early oil production. Finally, these results were combined with the fracture expansion mechanism model and A21 well model, and the analysis of fracturing flooding parameters based on the simulation results allowed for the following recommendations to be made: the total amount of fracturing flooding injection should be 15,000 m³, the injection rate should be 6 m³/min, the simmering time should be 3–7 days, and only one round of fracturing flooding is required. The mechanism of fracture expansion revealed in this paper can guide the design of fracturing flooding programs in the process of reservoir fracturing flooding development, which is of some significance to the development of the fracturing flooding of offshore reservoirs with low permeability. Full article