Search Results (29)

Due to factors such as low porosity and permeability, thin sand body thickness, and strong interlayer heterogeneity, the fluid flow in the tight reservoir (beach-bar sandstone reservoir) exhibits obvious nonlinear seepage characteristics. Considering the time-varying physical parameters of different types of sand bodies, a nonlinear seepage coefficient is derived based on permeability and capillary force, and a low-velocity nonlinear seepage model for beach bar sand reservoirs is established. Based on core displacement experiments of different types of sand bodies, the low-velocity nonlinear seepage coefficient was fitted and numerical simulation of low-velocity nonlinear seepage in beach-bar sandstone reservoirs was carried out. The research results show that the displacement pressure and flow rate of low-permeability tight reservoirs exhibit a significant nonlinear relationship. The lower the permeability and the smaller the displacement pressure, the more significant the nonlinear seepage characteristics. Compared to the bar sand reservoir, the water injection pressure in the tight reservoir of the beach sand is higher. In the nonlinear seepage model, the bottom hole pressure of the water injection well increases by 10.56% compared to the linear model, indicating that water injection is more difficult in the beach sand reservoir. Compared to matrix type beach sand reservoirs, natural fractures can effectively reduce the impact of fluid nonlinear seepage characteristics on the injection and production process of beach sand reservoirs. Based on the nonlinear seepage characteristics, the beach-bar sandstone reservoir can be divided into four flow zones during the injection production process, including linear seepage zone, nonlinear seepage zone, non-flow zone affected by pressure, and non-flow zone not affected by pressure. The research results can effectively guide the development of beach-bar sandstone reservoirs, reduce the impact of low-speed nonlinear seepage, and enhance oil recovery. Full article

Grouting, as a widely applicable and versatile foundation treatment technology, plays a crucial role in addressing seepage control problems in cover layers due to its flexibility and convenience. The effectiveness of grouting largely depends on slurry diffusion; however, due to the opaque nature of geotechnical media, the diffusion mechanism of slurry in the cover layers remains insufficiently understood. To investigate this, a visual grouting model device was designed and fabricated, and grouting tests were conducted using transparent soil materials to simulate the cover layers. The slurry diffusion patterns and the velocity field within the transparent soil were analyzed. The results show that, based on refractive-index matching, fused quartz sand of specific gradation and white mineral oil were selected as simulation materials for the cover layers. A stable slurry suitable for transparent grouting was also chosen to satisfy visualization requirements. The transparent soil grouting model, integrated with a Digital Image Correlation (DIC) monitoring system, has the advantages of demonstrating simple operation, real-time monitoring, and high precision. These tests verify the feasibility of visualizing slurry diffusion in cover layers. Furthermore, step-pressure grouting tests preliminarily reveal the dynamic mechanism of slurry diffusion. The results suggest that, in the cover layer, the cover layer in this grouting test is mainly splitting grouting, accompanied by compaction grouting. These methods offer new insights and methods for model testing of cover layer grouting mechanisms. 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

China’s natural gas demand is growing under the “dual carbon” goal. However, the peaking capacity of gas storage remains insufficient. Oil reservoir-based underground gas storage (UGS) has, thus, emerged as a critical research focus due to its potential for efficient capacity expansion. The complexity of seepage and phase change characteristics during the multi-cycle injection–production process has not been systematically elucidated. This study combines experimental and numerical simulations to examine the seepage and phase change characteristics. This study innovatively reveals the synergistic mechanism of permeability, pressure, and cycle. The control law of multi-factor coupling on the dynamic peaking capacity of UGS is first expounded. Oil–water mutual drive reduced oil displacement efficiency by 2.5–4.7%. Conversely, oil–gas mutual drive improved oil displacement efficiency by 3.0–4.5% and storage capacity by 4.7–6.5%. The fifth-cycle oil–gas mutual displacement in high-permeability cores (74 mD) under high pressure (22 MPa) exhibited reductions in irreducible water saturation (7.06 percentage points) and residual oil saturation (6.38 percentage points) compared with the first-cycle displacement in low-permeability cores (8.36 mD) under low pressure (16 MPa). Meanwhile, the gas storage capacity increased by 13.44 percentage points, and the displacement efficiency improved by 10.62 percentage points. Multi-cycle huff-and-puff experiments and numerical simulations revealed that post-depletion multi-cycle huff-and-puff operations can enhance the oil recovery factor by 2.74–4.22 percentage points compared to depletion. After five-cycle huff-and-puff, methane content in the produced gas increased from 80.2% to 87.3%, heavy components (C₈₊) in the remaining oil rose by 2.7%, and the viscosity of the remaining oil increased from 2.0 to 4.6 mPa·s. The deterioration of the physical properties of the remaining oil leads to a reduction in the recovery factor in the cycle stage. This study elucidates seepage mechanisms and phase evolution during multi-cycle injection–production, demonstrating the synergistic optimization of high-permeability reservoirs and high-pressure injection techniques for enhanced gas storage design and efficiency. Full article

Hydraulic fracturing is a critical process in the development of oil shale reservoirs. The presence of widespread bedding planes and natural fractures significantly influences the propagation of hydraulic fractures. Additionally, the injection point density plays a crucial role in the effectiveness of reservoir reconstruction. The Global Embedded Cohesive Zone Method (FEM-CZM) was employed to model the initiation and propagation of fractures from perforation holes, considering the combined effects of bedding planes and natural fractures. The results indicate the following: (1) the initiation and propagation of fractures from perforation holes lead to the co-propagation of two to four asymmetric main fractures, alongside open bedding planes and natural fractures; (2) larger bedding plane thickness and smaller bedding plane spacing promote hydraulic fractures’ tendency to propagate along the bedding planes, resulting in longer fracture lengths and predominance of tensile failure; and (3) a higher in situ stress difference facilitates the fracture’s penetration of the bedding plane, leading to an initial increase and subsequent decrease in fracture length. Tensile failure remains dominant, while the proportion of shear failure increases. Based on these findings, it is recommended to select fracturing sites with thicker bedding planes, larger bedding plane spacing, and a smaller vertical in situ stress field. Additionally, a perforation scheme with six injection points should be adopted to enhance the formation of high-efficiency seepage and heat transfer channels between hydraulic fractures, bedding planes, and natural fractures. 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

Volcanic rock reservoirs for oil and gas are known worldwide for their considerable heterogeneity. Micropores and fractures play vital roles in the storage and transportation of natural gas. Samples from volcanic reservoirs in Songliao Basin, CS1 and W21, belonging to the Changling fault depression and the Wangfu fault depression, respectively, have similar lithology. This study employs micro–nano CT scanning technology to systematically identify the key parameters and transport capacities of natural gas within volcanic reservoirs. Using Avizo 2020.1software, a 3D digital representation of rock core was reconstructed to model pore distribution, connectivity, pore–throat networks, and fractures. These models are then analyzed to evaluate pore/throat structures and fractures alongside microscopic parameters. The relationship between micropore–throat structure parameters and permeability was investigated by microscale gas flow simulations and Pearson correlation analyses. The results showed that the CS1 sample significantly exceeded the W21 sample in terms of pore connectivity and permeability, with connected pore volume, throat count, and specific surface area being more than double that of the W21 sample. Pore–throat parameters are decisive for natural gas storage and transport. Additionally, based on seepage simulation and the pore–throat model, the specific influence of pore–throat structure parameters on permeability in volcanic reservoirs was quantified. In areas with well–developed fractures, gas seepage pathways mainly follow fractures, significantly improving gas flow efficiency. In areas with fewer fractures, throat radius has the most significant impact on permeability, followed by pore radius and throat length. Full article

Inter-well frac-hit has become an important challenge in the development of unconventional oil and gas resources such as fractured tight sandstone. Due to the presence of hydraulic fracturing fractures, secondary induced fractures, natural fractures, and other seepage media in real formations, the acquisition of stress fields requires the coupling effect of seepage and stress. In this process, there is also stress sensitivity, which leads to unclear dynamic evolution laws of stress fields and increases the difficulty of the staged multi-cluster fracturing of horizontal wells. The use of a multi-stage stress-sensitive horizontal well production stress field prediction model is an effective means of analyzing the influence of natural fracture parameters, main fracture parameters, and multi-stage stress sensitivity coefficients on the stress field. This article considers multi-stage stress sensitivity and, based on fractured sandstone reservoir parameters, establishes a numerical model for the dynamic evolution of the production stress field in horizontal wells with matrix self-supporting fracture-supported fracture–seepage–stress coupling. The influence of various factors on the production stress field is analyzed. The results show that under constant pressure production, for low-permeability reservoirs, multi-stage stress sensitivity has a relatively low impact on reservoir stress, and the amplitude of principal stress change in the entire fracture length direction is only within the range of 0.27%, with no significant change in stress distribution; The parameters of the main fracture have a significant impact on the stress field, with a variation amplitude of within 2.85%. The ability of stress to diffuse from the fracture tip to the surrounding areas is stronger, and the stress concentration area spreads from an elliptical distribution to a semi-circular distribution. The random natural fracture parameters have a significant impact on pore pressure. As the density and angle of the fractures increase, the pore pressure changes within the range of 3.32%, and the diffusion area of pore pressure significantly increases, making it easy to communicate with the reservoir on both sides of the fractures. Full article

Oil spillages on a sea’s or an ocean’s surface are a threat to marine and coastal ecosystems. They are mainly caused by ship accidents, illegal discharge of oil from ships during cleaning and oil seepage from natural reservoirs. Synthetic-Aperture Radar (SAR) has proved to be a useful tool for analyzing oil spills, because it operates in all-day, all-weather conditions. An oil spill can typically be seen as a dark stretch in SAR images and can often be detected through visual inspection. The major challenge is to differentiate oil spills from look-alikes, i.e., low-wind areas, algae blooms and grease ice, etc., that have a dark signature similar to that of an oil spill. It has been noted over time that oil spill events in Pakistan’s territorial waters often remain undetected until the oil reaches the coastal regions or it is located by concerned authorities during patrolling. A formal remote sensing-based operational framework for oil spills detection in Pakistan’s Exclusive Economic Zone (EEZ) in the Arabian Sea is urgently needed. In this paper, we report the use of an encoder–decoder-based convolutional neural network trained on an annotated dataset comprising selected oil spill events verified by the European Maritime Safety Agency (EMSA). The dataset encompasses multiple classes, viz., sea surface, oil spill, look-alikes, ships and land. We processed Sentinel-1 acquisitions over the EEZ from January 2017 to December 2023, and we thereby prepared a repository of SAR images for the aforementioned duration. This repository contained images that had been vetted by SAR experts, to trace and confirm oil spills. We tested the repository using the trained model, and, to our surprise, we detected 92 previously unreported oil spill events within those seven years. In 2020, our model detected 26 oil spills in the EEZ, which corresponds to the highest number of spills detected in a single year; whereas in 2023, our model detected 10 oil spill events. In terms of the total surface area covered by the spills, the worst year was 2021, with a cumulative 395 sq. km covered in oil or an oil-like substance. On the whole, these are alarming figures. Full article

Marine gas hydrate formations are characterized by considerable water depth, shallow subsea burial, loose strata, and low formation temperatures. Drilling in such formations is highly susceptible to hydrate dissociation, leading to gas invasion, wellbore instability, reservoir subsidence, and sand production, posing significant safety challenges. While previous studies have extensively explored multiphase flow dynamics between the formation and the wellbore during conventional oil and gas drilling, a clear understanding of wellbore stability under the unique conditions of gas hydrate formation drilling remains elusive. Considering the effect of gas hydrate decomposition on formation and reservoir frame deformation, a multi-field coupled mathematical model of seepage, heat transfer, phase transformation, and deformation of near-wellbore gas hydrate formation during drilling is established in this paper. Based on the well logging data of gas hydrate formation at SH2 station in the Shenhu Sea area, the finite element method is used to simulate the drilling conditions of 0.1 MPa differential pressure underbalance drilling with a borehole opening for 36 h. The study results demonstrate a significant tendency for wellbore instability during the drilling process in natural gas hydrate formations, largely due to the decomposition of hydrates. Failure along the minimum principal stress direction in the wellbore wall begins to manifest at around 24.55 h. This is accompanied by an increased displacement velocity of the wellbore wall towards the well axis in the maximum principal stress direction. By 28.07 h, plastic failure is observed around the entire circumference of the well, leading to wellbore collapse at 34.57 h. Throughout this process, the hydrate decomposition extends approximately 0.55 m, predominantly driven by temperature propagation. When hydrate decomposition is taken into account, the maximum equivalent plastic strain in the wellbore wall is found to increase by a factor of 2.1 compared to scenarios where it is not considered. These findings provide crucial insights for enhancing the safety of drilling operations in hydrate-bearing formations. Full article

The production potential of highly deviated wells cannot be fully realized by conventional acid fracturing, as it can only generate a single fracture. To fully enhance the productivity of highly deviated wells, it is necessary to initiate multiple fractures along a prolonged well section to ensure the optimal number of fractures, thereby maximizing the economic returns post-stimulation. Thus, the number of fractures is a crucial parameter in the acid fracturing design of highly deviated wells. Considering factors such as the random distribution of natural fractures within the reservoir and interference between fractures during production, and, based on the oil–water two-phase flow equation, a three-dimensional reservoir–fracture production coupling model and its seepage difference model are established to simulate the production performance of highly deviated wells under varying conditions, including the number of fractures, fracture spacing, and conductivity parameters. A numerical model for the number of acid fracturing fractures in highly deviated wells is also established, in conjunction with an economic evaluation model. The simulation results indicate that the daily oil production of highly deviated wells increases with the increase in fracture number, fracture conductivity, fracture length, and reservoir permeability. However, over time, the daily oil production gradually decreases. Similarly, the cumulative production also increases with these parameters, but shows a downward trend over time. By conducting numerical simulations to evaluate the productivity and economy of highly deviated wells post-acid fracturing, it is determined that the optimal number of fractures to achieve maximum efficiency is six. The reliability of this result is confirmed by the pressure distribution cloud map of the formation after acid fracturing in highly deviated wells. Full article

The purpose of this study is to clarify the difference in oil production rules of conglomerate reservoirs with different pore structures during surfactant–polymer (SP) binary flooding and to ensure the efficient development of conglomerate reservoirs. In this paper, the full-diameter natural cores from the conglomerate reservoir of the Triassic Kexia Formation in the seventh middle block of the Karamay Oilfield (Xinjiang, China) are selected as the research objects. Two schemes of single constant viscosity (SCV) and echelon viscosity reducing (EVR) are designed to displace oil from three main oil-bearing lithologies, namely fine conglomerate, glutenite, and sandstone. Through comprehensive analysis of parameters, such as oil recovery rate, water content, and injection pressure difference, the influence of lithology on the enhanced oil recovery (EOR) of the EVR scheme is determined, which in turn reveals the differences in the step-wise oil production rules of the three lithologies. The experimental results show that for the three lithological reservoirs, the oil displacement effect of the EVR scheme is better than that of the SCV scheme, and the differences in recovery rates between the two schemes are 9.91% for the fine conglomerate, 6.77% for glutenite, and 6.69% for sandstone. By reducing the molecular weight and viscosity of the SP binary system, the SCV scheme achieves the reconstruction of the pressure field and the redistribution of seepage paths of chemical micelles with different sizes, thus, achieving the step-wise production of crude oil in different scale pore throats and enhancing the overall recovery of the reservoir. The sedimentary environment and diagenesis of the three types of lithologies differ greatly, resulting in diverse microscopic pore structures and differential seepage paths and displace rules of SP binary solutions, ultimately leading to large differences in the enhanced oil recoveries of different lithologies. The fine conglomerate reservoir has the strongest anisotropy, the worst pore throat connectivity, and the lowest water flooding recovery rate. Since the fine conglomerate reservoir has the strongest anisotropy, the worst pore throats connectivity, and the lowest water flooding recovery, the EVR scheme shows a good “water control and oil enhancement” development feature and the best step-wise oil production effect. The oil recovery rate of the two schemes for fine conglomerate shows a difference of 10.14%, followed by 6.36% for glutenite and 5.10% for sandstone. In addition, the EOR of fine conglomerate maintains a high upward trend throughout the chemical flooding, indicating that the swept volume of small pore throats gradually expands and the producing degree of the remaining oil in it gradually increases. Therefore, the fine conglomerate is the most suitable lithology for the SCV scheme among the three lithologies of the conglomerate reservoirs. Full article

Natural fractures are of paramount importance in storing carbon in shale oil reservoirs, where ultra-low porosity and permeability necessitate their essentiality for enhanced oil recovery. Therefore, comprehensively clarifying the characteristics of natural fractures in shale oil reservoirs is imperative. This paper focuses on investigating the microscopic features of natural fractures in organic-rich continental shale oil reservoirs that are commonly found in the Lower Jurassic strata of the Sichuan Basin, employing them as a representative example. Multiple methods were utilized, including mechanical testing, Kaiser testing, multi-scale CT scanning (at 2 mm, 25 mm, and 100 mm scales), and a numerical simulation of fluid seepage in fracture models. The results revealed that the in situ stress of the target seam displays the characteristic of σ_H > σ_v > σ_h, with σ_v and σ_h being particularly similar. The relatively high lateral stress coefficient (ranging from 1.020 to 1.037) indicates that the horizontal stresses are higher than the average level. Although the 2 mm CT scan provides a more detailed view of fractures and connected pores, it primarily exhibited more pore information due to the high resolution, which may not fully unveil additional information about the fractures. Thus, the 25 mm shale core is a better option for studying natural fractures. The tortuosity of the different fractures indicated that the morphology of larger fractures is more likely to remain stable, while small-scale fractures tend to exhibit diverse shapes. The simulations demonstrated that the stress sensitivity of fracture permeability is approximately comparable across different fracture scales. Therefore, our research can enhance the understanding of the properties of natural fractures, facilitate predicting favorable areas for shale oil exploration, and aid in evaluating the carbon storage potential of shale oil reservoirs. Full article

The development and application of predictive models to distinguish seepage slicks from oil spills are challenging, since Synthetic Aperture Radars (SAR) detect these events as dark spots on the sea surface. Traditional Machine Learning (ML) has been used to discriminate the Oil Slick Source (OSS) as natural or anthropic assuming that the samples employed to train and test the models in the source domain (D_S) follow the same statistical distribution of unknown samples to be predicted in the target domain (D_T). When such assumptions are not held, Transfer Learning (TL) allows the extraction of knowledge from validated models and the prediction of new samples, thus improving performances even in scenarios never seen before. A database with 26 geometric features extracted from 6279 validated oil slicks was used to develop predictive models in the Gulf of Mexico (GoM) and its Mexican portion (GMex). Innovatively, these well-trained models were applied to predict the OSS of unknown events in the GoM, the American (GAm) portion of the GoM, and in the Brazilian continental margin (BR). When the D_S and D_T domains are similar, the TL and generalization are null, being equivalent to the usual ML. However, when domains are different but statically related, TL outdoes ML (58.91%), attaining 87% of global accuracy when using compatible SAR sensors in the D_S and D_T domains. Conversely, incompatible SAR sensors produce domains statistically divergent, causing negative transfers and generalizations. From an operational standpoint, the evidenced generalization capacity of these models to recognize geometric patterns across different geographic regions using TL may allow saving time and budget, avoiding the collection of validated and annotated new training samples, as well as the models re-training from scratch. When looking for new exploratory frontiers, automatic prediction is a value-added product that strengthens the knowledge-driven classifications and the decision-making processes. Moreover, the prompt identification of an oil spill can speed up the response actions to clean up and protect sensitive areas against oil pollution. Full article

The presence of a high concentration of Cl⁻ in saltwater will erode the structure and facilities, reducing the stability and service life of the underground oil storage cavern. In order to reduce the risk of seawater intrusion, this paper studies the risk and prevention technology of seawater intrusion based on a case study of a coastal and large-span underground oil storage cavern. A refined three-dimensional hydrogeological model that comprehensively considers permeability coefficient partitions, faults, and fractured zones are constructed. The seepage fields and seawater intrusion risks of the reservoir site in its natural state, during construction, and during operation are examined, respectively. The study quantifies the water inflow and optimizes the seawater intrusion prevention technology. The results indicate that there is no risk of seawater incursion into the cavern under natural conditions. The water inflows after excavating the top, middle, and bottom sections of the main cavern are predicted to be 6797 m³/day, 6895 m³/day, and 6767 m³/day, respectively. During the excavation period, the water supply from the water curtain system is lower than the water inflow of the cavern, providing the maximum water curtain injection of 6039 m³/day. The water level in the reservoir area decreased obviously in the excavation period, but the water flow direction is from the cavern to the sea. Additionally, the concentration of Cl⁻ in the cavern area is less than 7 mol/m³; hereby, there are no seawater intrusion risks. When only the horizontal water curtain system is deployed, seawater intrusion occurs after 18 years of cavern operation. The concentration of Cl⁻ in the southeast of the cavern group exceeds 50 mol/m³ in 50 years, reaching moderate corrosion and serious seawater intrusion. In addition to the horizontal curtain above the cavern, a vertical water curtain system could be added on the southeast side, with a borehole spacing of 10 m and extending to 30 m below the cavern group. This scheme can effectively reduce seawater intrusion risk and extend the service life of the cavern. The findings of this research can be applied as guidelines for underground oil storage caverns in coastal areas to tackle seawater intrusion problems. Full article