Hydraulic Fracturing Research Articles

Preparation and Properties of Lightweight Amphiphobic Proppant for Hydraulic Fracturing.

The wettability of the proppant is crucial in optimizing the flowback of fracturing fluids and improving the recovery of the produced hydrocarbons. Neutral wet proppants have been proven to improve the fluid flow by reducing the interaction between the fluid and the proppant surface. In this study, a lightweight amphiphobic proppant (LWAP) was prepared by coating a lightweight ceramic proppant (LWCP) with phenolic resin, epoxy resin, polytetrafluoroethylene (PTFE), and trimethoxy(1H,1H,2H,2H-heptadecafluorodecyl)silane (TMHFS) using a layer-by-layer method. The results indicated that the LWAP exhibited a breakage ratio of 2% under 52 MPa (7.5 K) closure stress, with an apparent density of 2.12 g/cm3 and a bulk density of 1.21 g/cm3. The contact angles of water and olive oil were 125° and 104°, respectively, changing to 124° and 96° after displacement by water and diesel oil. A comparison showed that the LWAP could transport over a significantly longer distance than the LWCP, with the length increasing by more than 80%. Meanwhile, the LWAP displayed notable resistance to scale deposition on the proppant surface compared to the LWCP. Furthermore, the maintained conductivity of the LWAP was higher than that of the LWCP after displacement by water and oil phases alternately. The modified proppant could minimize production declines during hydrocarbon extraction in unconventional reservoirs.

Layered massive fracturing of carrier beds commercially unveils the deep tight sandstone gas reserves in Sichuan Basin

Achieving commercial production from deep tight gas formations poses challenges to existing geological and engineering technologies. Xujiahe tight sandstone gas, deeply buried in the Western Sichuan Basin, is proven with enormous reserves; however, preliminary hydraulic fracturing trials mostly failed to bring up the productivity. From the angle of incorporating geological and engineering knowhow, we first adopted the carrier beds theory to distinguish the favorable zones in Xujiahe Formation, then a dual sweet spot identification criterion was established based upon analytic hierarchy process, which links major geological and engineering parameters together. Provided the identified sweet spot, hydraulic fracture conductivity was then optimized to maximize the productivity. Fracturing operational parameters consisting of fluid volume and pumping, proppant size and addition, and fluid formula were then screened to secure high conductivity. Implementation of this updated geological-engineering technical route in exploiting Xujiahe tight gas reservoirs turns out to be a great success with an average gas rate of 130 Mm3/d/well during the early production stage in 14 wells. Electromagnetic monitoring further demonstrated the effectiveness of precise massive fracturing by visualizing the morphology of fracture clusters. Comparative productivity analyses manifested the breakthrough of this technical route over preceding ones in Xuejiahe gas reservoirs, providing a superior reference for discovering and developing deep tight gas resources around the world.

Characterization of flowback and produced water from shale oil and gas wells fractured with different levels of recycled water

ABSTRACT Hydraulic fracturing requires large volumes of water, and it is therefore crucial to establish sustainable water sources. We analyzed the flowback and water produced from three wells using different fresh-to-recycled water ratios for hydraulic fracturing: freshwater only, 20% recycled water, and one-seventh (∼15%) recycled water. Water samples were collected over a 36-day period (flowback started on day 0). There were no significant differences between the total organic carbon (TOC) levels of the wells, but the total dissolved solid (TDS) concentrations increased for all wells over time, and there were significant differences among the wells. The TDS level of the well fractured with 20% recycled water was significantly higher than that of the other wells. Liquid chromatography quadruple time-of-flight mass spectrometry revealed ethoxylated functional groups in all three wells. Agilent qualitative analysis software B.06.00 was used to perform a qualitative analysis based on the exact mass of organic compounds within 1 ppm mass accuracy. The results of this study provide new insights into the quality of flowback and produced water from wells fractured using different fresh-to-recycled water ratios and can be used as a reference for improving the reusability of treated water and reducing wastewater discharge.

Numerical simulation study of fracture propagation by internal plugging hydraulic fracturing

Internal temporary plugging fracturing technology improves the stimulated volume by forming a more complex fracture network, significantly enhancing the reservoir stimulation effect and effectively developing unconventional oil and gas resources. However, the current understanding of the fracture propagation mechanism on internal temporary plugging fracturing is still unclear, making it difficult to determine the main controlling factors that affect the shape of the fractures. In addition, the lack of practical numerical simulation methods for temporary plugging fracturing makes it challenging to provide guidance for field scheme design. Utilizing the finite element cohesive zone method, which incorporates globally embedded cohesive elements, this study constructs a comprehensive numerical model to investigate the propagation behavior of temporarily plugging fracturing fractures. The model delves into the impact of various geological and construction parameters on the opening conditions of branch fractures during the temporary plugging fracturing process, as well as the propagation patterns of fractures within naturally fractured reservoirs. The research findings indicate that the construction factors have the following impacts: When the pumping rate and viscosity of the fracturing fluid are comparatively high, the resulting fluid pressure within the fracture escalates, resulting in the creation of numerous branch fractures within the naturally fractured reservoir. This, in turn, augments the fracture’s complexity. However, these two factors have little influence on the maximum deflection distance of the deflected fracture. As for the geological factors, an increase in the horizontal stress difference will decrease the maximum deflection distance of the deflected fracture, reducing the number of natural fractures intersected and shortening the length of the deflected fracture. Conversely, an increase in the approach angle will increase the maximum deflection distance of the deflected fracture, thereby expanding the affected area. Additionally, the influence of Young’s modulus and Poisson’s ratio on fracture propagation is very slight. A decrease in the tensile strength of natural fractures leads to more natural fractures being intersected during the process, resulting in increasing the length of the fracture and an improvement in the complexity of the fracture grid.

A study on the impact of ultrasonic-stimulated clean fracturing fluid on the pore structure of medium to high rank coal

The pore structure of coal plays a key role in the effectiveness of gas extraction. Conventional hydraulic fracturing techniques have limited success in modifying the pore structure using clean fracturing fluid (CFF), and the stimulating effects of ultrasonic can enhance the effectiveness of CFF in modifying coal pore structures. To research the effects of ultrasonic stimulation on the pore structure of medium to high-rank coal when using CFF, this study employed mercury intrusion porosimetry (MIP) and low-temperature nitrogen adsorption (LT-N2A) methods to analyze the changes in pore structures after cooperative modification. The results indicate that the pore volume and surface area of medium to high rank coal exhibit an increase and followed by a decrease with increasing Ro,max values, while the average pore diameter and permeability demonstrate a decrease and followed by an increase with Ro,max. Although there are some variations in the results of MIP and LT-N2A analysis for different pore size ranges, the overall findings suggest that ultrasonic stimulation in conjunction with CFF effectively alters the coal pore structure. The most significant improvement was observed in coking coal, where pore volume increased by 22%, pore area decreased by 11% and tortuosity decreased by 47%. The improvement of lean coal is the smallest, the pore volume increases by about 7%, and the surface area decreases by about 14%. It is found that the modification of coal pore volume is mainly concentrated in transition pores and macropores. These research outcomes provide valuable insights into the application of ultrasonic technology in coalbed gas extraction.

Numerical study on Slurry-induced Fracturing Pressure of Cohesive Soil

The stability of the tunnel face during the slurry shield tunnelling is controlled by the slurry pressure in the slurry chamber, and excessive slurry pressure will cause fracturing on excavation face. In order to prevent the occurrence of slurry fracturing, it is necessary to conduct a detailed study on the slurry support pressure when the slurry fracturing occurs. In this study, the hydraulic fracturing experiment of cohesive soil samples was carried out by the self-developed hydraulic fracturing device, and the improved XFEM was used to simulate the experiment process. The influence of various factors on the fracturing pressure was analyzed, and the accuracy of the numerical simulation method was also verified. In addition, the calculation method of fracturing pressure of soft cohesive soil is obtained by fitting the influence of each factor. The results show that the improved XFEM can accurately simulate the shear failure of soft cohesive soil. The fracturing pressure increases linearly with the increase in the circumferential pressure, indicating that a higher overburden of the tunnel can help resist the initial fracturing induced by shield tunneling. The fracturing pressure increases with an increase in the unconfined compressive strength as well as the slurry viscosity. Based on the regression analysis of the numerical results, an empirical approach was proposed for estimating the slurry-induced fracturing of soil.

Mechanisms of Proppant Transport in Rough Fractures of Offshore Unconventional Reservoirs: Shale and Tight Sandstone

After hydraulic fracturing, unconventional reservoirs frequently encounter challenges related to limited effective proppant support distance and suboptimal proppant placement. Due to the strong heterogeneity of offshore reservoirs, which causes varying fracture roughnesses depending on different lithologies, a systematic study of the relationship between roughness and proppant transport could optimize operational parameters. This study incorporates the box dimension method for fractal dimension analysis to quantify roughness in auto-correlated Gaussian distributed surfaces created by true triaxial tests. Combined with the numerical analysis of (computational fluid dynamics) CFD-DEM (discrete element method) for bidirectional coupling, the laws of proppant deposition and transport processes within fractures with different roughnesses are obtained through comparative verification simulations. The results show that for rougher fractures of shale, the proppants are transported farther, but at JRC_52, (joint roughness coefficient), where there may be plugging in curved areas, there is a risk of near-well blockages. Compared to the smooth model, fluctuations in JRC_28 (tight sandstone) drastically increase turbulent kinetic energy within the fracture, altering particle transport dynamics. Moreover, smaller proppants (d/w ≤ 0.3) exhibit better transport capacity due to gravity, but the conductivity of the proppant is limited when the particles are too small. A d/w of 0.4 is recommended to guarantee transport capacity and proppant efficiency near the well. Additionally, proppants injected sequentially from small to large in shale fractures offer optimal propping effects, and can take advantage of the better transport capacity of smaller proppants in rough fractures. The large proppant (d/w = 0.8) is primarily deposited by gravity and forms a sloping sand bed, which subsequently ensures the aperture of the fractures. This research provides a fresh perspective on the influence of fracture roughness on proppant transport in offshore unconventional reservoirs and offers valuable considerations for the order of proppant injection.

Evaluation of Fracturing Effect of Tight Reservoirs Based on Deep Learning.

The utilization of hydraulic fracturing technology is indispensable for unlocking the potential of tight oil and gas reservoirs. Understanding and accurately evaluating the impact of fracturing is pivotal in maximizing oil and gas production and optimizing wellbore performance. Currently, evaluation methods based on acoustic logging, such as orthogonal dipole anisotropy and radial tomography imaging, are widely used. However, when the fractures generated by hydraulic fracturing form a network-like pattern, orthogonal dipole anisotropy fails to accurately assess the fracturing effects. Radial tomography imaging can address this issue, but it is challenged by high manpower and time costs. This study aims to develop a more efficient and accurate method for evaluating fracturing effects in tight reservoirs using deep learning techniques. Specifically, the method utilizes dipole array acoustic logging curves recorded before and after fracturing. Manual labeling was conducted by integrating logging data interpretation results. An improved WGAN-GP was employed to generate adversarial samples for data augmentation, and fracturing effect evaluation was implemented using SE-ResNet, ResNet, and DenseNet. The experimental results demonstrated that ResNet with residual connections is more suitable for the dataset in this study, achieving higher accuracy in fracturing effect evaluation. The inclusion of the SE module further enhanced model accuracy by adaptively adjusting the weights of feature map channels, with the highest accuracy reaching 99.75%.

A hydraulic-mechanical coupled triple porosity fractal model considering action mechanisms and gas transport mechanisms in carbon-hydrogen reservoirs

The shale formation, a common carbon-hydrogen reservoir, has numerous nanoscale pores that facilitate multiple gas transport mechanisms, including viscous flow, slip flow, Knudsen diffusion, and surface diffusion. Additionally, various action mechanisms involving effective stress, real gas effect, gas adsorption and desorption, and fracture-pore characteristics significantly influence gas transport. In this study, we conceptualize shale as a triple porosity medium comprising organic matrix, inorganic matrix, and microfractures. For each system, its hydraulic-mechanical coupled model with action mechanisms and gas transport mechanisms is derived based on fractal theory. After validating the model with Barnett and Marcellus data, the evolution of apparent permeability and gas pressure is studied, as well as the influences of pore fractal features, the real gas effect, and the number of hydraulic fractures on gas extraction. Simulation results indicate that, in comparison to organic matrix, inorganic pore fractal features exert a more noticeable effect on cumulative production. The real gas effect is critical in gas transport and reservoir reserve estimation; disregarding this effect results in a 17.4% underestimation of cumulative gas production by the 1600th day. Fracture interference attenuates the improvement in cumulative production gains from increased hydraulic fracture numbers.

Characterization of Adsorbed Hydrocarbons in Deposit Sands and Well Fracture in the Burgos Basin

Objective: The objective of this research is to determine the potential adsorption by the solids carried by the hydrocarbon production stream to the surface by characterization to identify its origin. Theoretical framework: In the natural gas producing wells of the Burgos Basin, there is the presence of solids in the production fluids, these can be from the reservoir or from fracture. The reservoir solids are created from the carbonates, sandstones and shales inside the well, the fracture solids are better known as props, they are mixed with the drilling fluid so that inside the well they act as packs in the fractures where the hydrocarbon can flow for extraction. In this Basin, horizontal hydraulic fracturing is used for the extraction of hydrocarbons, the solids present adsorb part of the hydrocarbons and are contaminated with them. Method: Sand samples from 4 wells were used, which were extracted with Soxhlet equipment to separate the organic content of the sand. Using ASTM (2003) and US EPA (1996) methods D5369-93 and 3540C-3541 as a reference. Subsequently, the hydrocarbon concentrate was fractionated using the method reported in the manual of soil analysis techniques of Fernández et al., (2006) who adapted the methods 3600C, 3610B and 3611B of the US EPA (1996). The analytical method consisted of reading the spectra of each fraction in a UV-Visible Shimadzu UV-1800 spectroscopy equipment and by FT-IR spectrophotometry, in a Nicolet iS10 equipment, with a DTGS KBr detector. The physical characterization of the sands was performed by recording the particle size using the API-RP56 standard. Finally, X-ray diffraction is used to determine the phases of the sands by the method 05LA-34080109-DRX-MP-01. Results and discussion: The amount of total hydrocarbon extracted from the sands was in a range of 2,975-0,060 gr. The identification of hydrocarbons extracted by Uv-Visible and FTIR showed functional groups of aliphatic, polycyclic and nitrogen compounds. The particle size of the sands was measured between 45-311 nm. And finally RX identified the type of sand to analyze, being well 1: reservoir sand, well2: fracture sand, well 3: fracture sand and well 4: reservoir sand. Implications of the research: This research presents a study on the classification of the type of sands that are being dragged to the surface with the hydrocarbon stream of well production. These are data that show a fact that occurs and gives the certainty of what happens at the bottom of the well. Originality/value: The analysis of the results allows decisions to be taken to prevent corrosion and plugging problems of surface equipment, which can cause explosions such as the one of September 19, 2012 in the PEMEX gas pipeline at the Km 19 Measuring Center in Reynosa, Tamps. Mexico.

EXPERIMENTAL STUDY ON THE FRACTURE CONDUCTIVITY IN SHALE OIL PRODUCTION

Unconventional oil and gas resources, such as shale oil and gas, are gradually attracting great attention from all countries of the world. Horizontal drilling and large-scale hydraulic fracturing technology are used to efficiently extract oil from shale formation. Effective placement of the proppant in the fractures and high long-term conductivity are the keys to solve the problems of oil well flow rate increase in shale oil and gas fields. In this work, the sieve analysis method and FCMS-V fracture conductivity determination device, as well as scanning electron microscope are used. They are used to experimentally investigate the filtration characteristics of hydraulic fracturing fractures and establish the key factors affecting the filtration characteristics. The object of the study is the core of the oil-saturated DG shale formation of Songliao Basin. Also in this paper, the indentation and crushing mechanism of proppant under reservoir conditions is studied. The influence of various factors was evaluated qualitatively and quantitatively. The following studies were conducted: the effect of sand granule size on conductivity, the effect of grain size distribution on conductivity, the effect of proppant concentration on conductivity, the effect of fracture closure pressure on conductivity, and the effect of proppant indentation on conductivity. The granule sizes of the proppant used range from 30/50 to 70/140 mesh. Proppant concentration: 2,5; 5; 10 kg/m2. Ratios of granule sizes for used mixtures: 1:1:1, 1:2:7, 1:4:5.And crack clamping pressure from 20 to 40 MPa. As a result of the study, dependences of initial and long-term fracture conductivity on clamping pressure, granulometric composition of proppant and its concentration were obtained. Using a scanning electron microscope, the degree of indentation and crushing of proppant under reservoir conditions in two media, namely shale core and steel plates, was visually evaluated. The results of experimental studies can be used to optimize the shale oil development system and have scientific and practical significance for shale oil production in continental deposits.

VELOCITY AND EVOLUTION OF SHOCK WAVES IN SAND WITH INCREASING WATER CONTENT

Interest in the problems of shock wave propagation in saturated porous media is associated with studying seismic exploration issues, modeling the hummer effect during hydraulic fracturing, studying the water-gas impact on formations for the purpose of efficient oil production, etc. Experimental work on waves in bulk media is usually carried out in shock tubes. Traditionally, shock tubes are used to study the characteristics of the propagation of shock waves in various media, to analyze the wave properties of these media based on the speed of the shock waves and the change in the shape of the pulse along the passage of the first – main pulse. In a shock tube equipped with a section of bulk media, the wave is repeatedly reflected from the surface of the porous medium under study and the upper end of the tube. Re-reflected waves can be used to study changes in the environment that occurred under the influence of a shock wave, i.e. as probing pulses. In this article, sounding is understood as identifying acoustic properties (changing the shape of shock pulse diagrams and their velocities). This paper presents the results of experimental studies of the propagation of shock waves of small amplitude in sand with a volumetric content of liquid in the pore space from 0 to 40 %, and illustrates the influence of the presence of liquid in the pores on the shape of the main and probing pulses. The research was carried out using the Shock Tube installation, in the Laboratory of Experimental Hydrodynamics of the Mavlyutov Institute of Mechanics of Ufa Branch RAS. An increase in the speed of wave propagation was established with increasing water saturation of sand in the range from 0 to 40 %. An increase in the amplitude of reflected waves when passing through sand, the formation of peaks and stretching of pulses were discovered. The research results can be used in processing geophysical data to interpret seismograms of sandy deposits saturated with gas-liquid systems.

An analytical solution model of oil–water dynamic imbibition considering dynamic contact angle effect and osmotic pressure at micro-nano scale

Spontaneous imbibition is one of the important mechanisms to enhance oil recovery during hydraulic fracturing process of shale reservoirs. The dynamic contact angle effect in imbibition kinetics of liquid–liquid system is complicated due to the large number of micro-nano pores in shale reservoir. Moreover, the content of clay minerals is high, the chemical osmosis effect is significant, and the impact of osmotic pressure on imbibition is not clear. In order to clarify the dynamic contact angle effect in imbibition kinetics and correctly understand the role of osmotic pressure in imbibition process. In this paper, based on the molecular kinetic theory (MKT), the dynamic contact angle effect is successfully coupled with imbibition kinetic equation, and a capillary pressure equation is developed. On the basis, considering the effects of osmotic pressure, external displacement pressure and boundary layer effect on imbibition, An analytical solution model of oil–water dynamic imbibition model is developed. The results shows that under the respective effects of capillary pressure and osmotic pressure, the imbibition velocity initially stabilizes before increasing over time; under the action of displacement pressure, the imbibition velocity increases with time. Imbibition velocity is directly proportional to interfacial tension and capillary radius, but inversely proportional to contact angle and oil viscosity. With the salt concentration difference increasing from 80 mol/m3 to 4710 mol/m3, the imbibition velocity increased by about 54 times. Compared with the membrane efficiency of 30 % and 5 %, the imbibition velocity is increased by 4.95 times. In this work, the dynamic contact angle effect in the imbibition kinetics of liquid–liquid system was accurately characterized, clarified the action mechanism of osmotic pressure, and provided theoretical support for enhancing oil recovery of shale reservoirs.

Effect of bedding planes and property contrast between layers on the propagation mechanism of hydraulic fracture height in shale reservoirs

Bedding planes and property contrast between layers plays an important role in preventing hydraulic fracture height extension in shale reservoirs. However, the intrinsic causes of fracture containment have not been elucidated, and few studies have considered the effects of mixed factors on fracture height extension. Based on the continuum-discontinuum element method, a 3D hydraulic-mechanical coupling model was established to explore the influence mechanism of bedding planes, stress and modulus difference between layers, and mixing factors on fracture height extension in a transversely isotropic shale reservoir. Shear failure usually occurs preferentially when the fracture approaches the bedding plane, and the essential reason for fracture containment is that the shear slip on the bedding plane blunts the fracture tip. The stronger stress barrier formed by the higher minimum principal stress in adjacent formation effectively enables the fracture to terminate at the interlayer interface. The lower modulus in adjacent formation is more prone to rock initiation, but the larger elastic deformation absorbs the fracture tip stress and impedes height propagation. The comprehensive effect of bedding planes and property contrast between layers on fracture propagation is more complex than that of a single factor. When different factors have positive effects on fracture containment, the fracture is easier to terminate at the bedding plane. Otherwise, the dominant factor determines whether the fracture can be captured. No matter what the conditions, the pressure relief in the bedding plane can slow down the propagation rate. The findings can offer theoretical support for predicting fracture height during field fracturing in shale reservoirs.

Experimental study on hydraulic fracture propagation behavior in heterogeneous shale formations

The study of fracture propagation in heterogeneous shale is a crucial prerequisite for the investigation of heterogeneous cluster and perforation parameters optimization. In this paper, we conduct a physical simulation fracturing experiment on heterogeneous shale to investigate the effects of various influencing factors, such as shale bedding, near-wellbore fractures, lithological changes, and the presence of fractures surrounding the perforation hole, on fracture propagation law and morphology. Our research demonstrates that during shale fracturing, shear dislocation typically occurs between layers, resulting in the separation of different layer planes. The main fracture primarily propagates through layers in a stepped manner. The presence of sandstone in heterogeneous shale significantly impedes fracturing fractures, causing significant distortion and deviation. As the scale of natural fractures increases, it tends to cause the fracturing fracture to twist and change direction. The natural fractures network can also lead to the distortion of fracturing fractures, albeit to a lesser extent than large-scale natural fractures. The presence of micro fractures parallel to the perforation axis surrounding the perforation hole enhances the ability of the main fracturing fractures to pass through natural fractures.

Data-driven multiscale geomechanical modeling of unconventional shale gas reservoirs: a case study of Duvernay Formation, Alberta, West Canadian Basin

The Duvernay Formation in Canada is one of the major oil and gas source formations in the Western Canadian Sedimentary Basin, located at its deepest point. While it demonstrates promising development potential, challenges arise in the urgent need for integration of geology and engineering models, as well as in optimizing sweet spots, particularly as infill wells and pads become central operational objectives for the shale gas field. A lack of the geomechanical understanding of shale gas reservoirs presents a significant obstacle in addressing these challenges. To overcome this, we implemented data acquisition and prepared historical models and profiles, resulting in an extended high-resolution geological and reservoir property model with a fine grid system. Subsequently, a 3D full-field multi-scale geomechanical model was constructed for the main district by integrating seismic data (100 m), geological structures (km), routine logs (m), core data (cm), and borehole imaging (0.25 m), following a well-designed workflow. The predicted fracturability index (brittleness) ranges from 0.6 to 0.78, and a lower horizontal stress difference (STDIFF) is anticipated in the target formation, Upper Duvernay_D, making it a favorable candidate for hydraulic fracturing treatment. Post-analysis of the multi-disciplinary models and various data types provides guidelines for establishing a specific big database, which serves as the foundation for production performance analysis and aggregate sweet spot analysis. Fourteen geological and geomechanical candidate parameters are selected for the subsequent sweet spot analysis. This study highlights the effectiveness of multi-scale geomechanical modeling as a tool for the integration of multi-disciplinary data sources, providing a bridge between geological understanding and future field development decisions. The workflows also offer a data-driven framework for selecting parameters for sweet spot analysis and production dynamic analysis.

Analysis of near-well hydraulic fracture propagation behavior in inhomogeneous deep-sea hydrate-bearing-sediments

The hydrate reservoirs exhibit significant inhomogeneity due to the presence of various hydrate types, potentially impacting the effectiveness of hydraulic fracturing. The investigation of the relationship between hydraulic fracture extension patterns and pure hydrate blocks for varying conditions is highly valuable. The extended finite element method (XFEM) is applied to reveal the influence mechanism of hydrate heterogeneity on fracture propagation law. First, compared with the results of the fracturing experiments in hydrate-bearing clayey silt sediments, the accuracy of the method is verified. Subsequently, a model for fracturing near-well in deep-sea inhomogeneous hydrate-bearing-sediments is established, containing sedimentary matrix and pure hydrate blocks. The effects of disseminated hydrate saturation, injection rate, horizontal stress difference and the distribution location of pure hydrate blocks on the fracture extension path are investigated. Due to the pure hydrate is much more brittle, most hydraulic fractures, once encountered with it, choose to bypass. If the fracture is unable to bypass the pure hydrate block, the fracture appears to arrest and penetrate. The seafloor sediment matrix is characterized by its loose nature, and a continuous increase in the injection rate may result in the competing development of the fractures in both length and width directions.

Promoting Sustainable Development of Coal Mines: CNN Model Optimization for Identification of Microseismic Signals Induced by Hydraulic Fracturing in Coal Seams

Borehole hydraulic fracturing in coal seams can prevent dynamic coal mine disasters and promote the sustainability of the mining industry, and microseismic signal recognition is a prerequisite and foundation for microseismic monitoring technology that evaluates the effectiveness of hydraulic fracturing. This study constructed ultra-lightweight CNN models specifically designed to identify microseismic waveforms induced by borehole hydraulic fracturing in coal seams, namely Ul-Inception28, Ul-ResNet12, Ul-MobileNet17, and Ul-TripleConv8. The three best-performing models were selected to create both a probability averaging ensemble CNN model and a voting ensemble CNN model. Additionally, an automatic threshold adjustment strategy for CNN identification was introduced. The relationships between feature map entropy, training data volume, and model performance were also analyzed. The results indicated that our in-house models surpassed the performance of the InceptionV3, ResNet50, and MobileNetV3 models from the TensorFlow Keras library. Notably, the voting ensemble CNN model achieved an improvement of at least 0.0452 in the F1 score compared to individual models. The automatic threshold adjustment strategy enhanced the identification threshold’s precision to 26 decimal places. However, a continuous zero-entropy value in the feature maps of various channels was found to detract from the model’s generalization performance. Moreover, the expanded training dataset, derived from thousands of waveforms, proved more compatible with CNN models comprising hundreds of thousands of parameters. The findings of this research significantly contribute to the prevention of dynamic coal mine disasters, potentially reducing casualties, economic losses, and promoting the sustainable progress of the coal mining industry.

Pressure Source Model of the Production Process of Natural Gas from Unconventional Reservoirs

This work is focused on developing a computational model to predict the production rate and pressure evolution of natural gas from unconventional reservoirs, particularly shale gas deposits. The model is based on the principle of conservation of mechanical energy and was developed from the transient solution of Bernoulli’s equation. This solution was obtained by computing the pressure evolution in the well resulting from the combined action of extracting the free gas and of gasification from kerogen. The transient behavior of gas production by hydraulic fracturing was calculated by numerically integrating Bernoulli’s equation. The curves representing gas flow evolution were considered as a series of stepwise steady states under a constant gas flow rate, similar to the pressure–time curves. These time steps were connected by instantaneous drops in pressure or gas flow rates. On the other hand, the delayed release of the adsorbed and dissolved gas in the kerogen was accurately calculated by introducing a semi-empirical gas pressure source term into the gas well pressure equation. The effect of this source is to gradually increase the gas pressure in the reservoir, emulating the gas release mechanisms from the organic matter. Model validation was based on production data from the unconventional reservoirs Eagle Ford, U.S.A., and Burgos basin, México. The initial measured gas production rate was used to determine a global friction factor of the gas flowing out from soil cracks and ducts. Additionally, measured production rate data were used to determine the coefficients of the source term function. Pearson correlation coefficients of 0.97 and 0.96 were obtained for Eagle Ford and Burgos basins data, respectively. In contrast, the corresponding coefficients calculated from the traditional Arps’ model were 0.89 and 0.5, respectively. The present pressure source model (PSM) represents a new approach to characterize the process of gas production from unconventional reservoirs, proving to be accurate in forecasting both the gas flow rate and pressure evolution during gas production. The postulated pressure source term was shown to mimic the desorption and diffusion kinetics, which release free gas from the kerogen.

Study of the evolution characteristics of fiber-optic strain induced by the propagation of bedding fractures in hydraulic fracturing

Shale reservoirs contain numerous bedding fractures, making the formation of complex fracture networks during fracturing a persistent technical challenge in evaluating shale fracture morphology. Distributed optical fiber sensing technology can effectively capture the process of fracture initiation and propagation, yet the evaluation method for the initiation and propagation of bedding fractures remains immature. This study integrates a distributed optical fiber sensing device based on optical frequency domain reflectometry (OFDR) with a large-scale true tri-axial fracturing physical simulation apparatus to conduct real-time monitoring experiments on shale samples from the Lianggaoshan Formation in the Sichuan Basin, where bedding is well-developed. The experimental results demonstrate that two bedding fractures in the shale sample initiated and propagated. The evolution characteristics of fiber-optic strain in a horizontal adjacent well, induced by the initiation and propagation of bedding fractures, are characterized by the appearance of a tensile strain convergence zone in the middle of the optical fiber, flanked by two compressive strain convergence zones. The initiation and propagation of the distal bedding fracture causes the fiber-optic strain in the horizontal adjacent well to superimpose, with the asymmetric propagation of the bedding fracture leading to an asymmetric tensile strain convergence zone in the optical fiber. Utilizing a finite element method coupled with a cohesive element approach, a forward model of fiber-optic strain in the horizontal adjacent well induced by the initiation and propagation of hydraulic fracturing bedding fractures was constructed. Numerical simulation analyses were conducted to evaluate the evolution of fiber-optic strain in the horizontal adjacent well, confirming the correctness of the observed evolution characteristics. The presence of a "wedge-shaped" tensile strain convergence zone in the fiber-optic strain waterfall plot, accompanied by two compressive strain convergence zones, indicates the initiation and propagation of bedding fractures during the fracturing process. These findings provide valuable insights for interpreting distributed fiber-optic data in shale fracturing field applications.