Horizontal Fracture Research Articles

Investigating the potential of unconventional resources in the Midland Basin: A comprehensive chemostratigraphic analysis of a Cline Shale (Wolfcamp-D) core

Basinal mudrocks assigned to the Wolfcamp Group in the Midland Basin are prolific producers of oil and gas. Technological advancements in horizontal drilling and hydraulic fracturing have been successful in the exploitation of oil and gas from these tight mudrocks. However, many challenges remain unsolved in capturing their macroscale compositional variations to enhance recovery factors and delineate “sweet spots”. To gain improved insights into this fine-grained system, high resolution chemostratigraphic (XRF) data was integrated with mineralogical measurements (XRD), logs, thin sections, and TOC readings, as well as hierarchical cluster analysis to: 1) develop a sequence stratigraphic framework, and 2) reconstruct paleo-redox, as well as ancient water-mass, conditions within the Cline Shale (Wolfcamp-D) from a core in the Midland Basin.This study revealed the presence of three chemo-stratigraphically distinct depositional sequences in the Cline Shale, herein termed Lower, Middle, and Upper Cline from the base upwards. All three units exhibit distinct mineralogical and petrophysical characteristics, were correlated across the basin, and interpreted as third-order sequences. Superimposed onto the three interpreted third-order sequences within the Cline, are potential higher frequency (fourth-order) sequences. These fourth-order sequences typically consist of a lower interval, interpreted as lowstand deposits and an upper interval, which is interpreted as transgressive and highstand deposits. The lower interval is interpreted to be deposited during highly reducing conditions while the upper interval is interpreted to be deposited under suboxic conditions. The highest organic matter preservation is associated with the interpreted lowstand deposits, especially in the Upper Cline. Optimal landing zones (20 ft) are recognized in the upper zone of the Cline Shale based on their high resistivity, total organic richness, elevated siliceous content, and reduced percentage of clay minerals. These zones have been correlated with several nearby wells.The current study demonstrates the wealth of information that can be gained from a single core/well when properly investigated at high resolution with measurements on a cm-scale. The observed shifts in the chemistry of the sediments character and composition are distinct, with implications for sequence stratigraphic analysis, the reconstruction of ancient water-mass conditions, and the identification of “sweet spots” for hydrocarbon resources. The provided analysis lays a foundational basis for further studies in the region, serving as critical data input for expansive regional research efforts.

Dynamic prediction of fracture propagation in horizontal well hydraulic fracturing: A data-driven approach for geo-energy exploitation

Accurate and efficient prediction of hydraulic fracturing fracture propagation is of utmost importance for unconventional reservoir development. Traditional numerical simulation methods require specialized domain knowledge and technical expertise, and machine learning approach can be an alternative predictive tool for fracture propagation. Additionally, existing neural networks cannot be directly applied to hydraulic fracturing scenarios influenced by multiple coupled factors. Thus, this study presents an innovative approach, “AE-ATT-ConvLSTM”, that integrates an additional Convolutional Layer, Autoencoder, and an Attention Mechanism Feature Fusion Layer into the architecture of a Convolutional Long Short-Term Memory (ConvLSTM) sequential image prediction network. This approach aims to predict fracture propagations in different fracturing stages of horizontal wells. The proposed model is trained on a sample dataset consisting of 5000 instances of hydraulic fracturing in horizontal wells. The dataset includes crucial data such as fracture propagation images, wellbore perforation images, natural fracture images, pumping schedules, and reservoir properties. The model achieves remarkable results, with an MSE less than 15 × 10−5, a maximum SSIM of 0.93, and an average FMAE less than 48. The research findings demonstrate that this method significantly enhances prediction efficiency and provides new insights for predicting fracture morphology and optimizing fracturing design.

A new approach for fracture parameters optimization of multi-fractured horizontal wells: Virtual boundary method

Horizontal well fracturing technology stands as the cornerstone for achieving large-scale commercial production in shale reservoirs. Yet, the complexity of fracture variables within horizontal wells, comprising both discrete and continuous factors, presents a formidable challenge for optimization. Existing methods struggle to holistically optimize these mixed fracture parameters, including discrete fracture number, continuous fracture location, and half-length. This study pioneers a fracture deployment optimization approach tailored for fractured horizontal wells in shale reservoirs, leveraging the innovative virtual boundary method (VBM). Initially, a virtual boundary model is developed by extending the length of the fracturing horizontal wellbore, defining the extended area as a virtual reservoir devoid of hydrocarbon. Subsequently, the net present value (NPV) is adopted as the objective function, with continuous fracture location and half-length serving as optimization variables. The modified simultaneous perturbation stochastic approximation (mSPSA) algorithm is then employed for optimization. Following optimization, the optimized fractures within the virtual area are identified and deleted via position identification, enabling the comprehensive optimization of fracture number, location, and half-length. Notably, the computational efficiency of this method surpasses existing approaches by a factor of 5.1 compared to the bisection nested SPSA optimization method. Validation through three calculation cases, encompassing homogeneous reservoir, distinct sweet spot reservoir, and strongly heterogeneous reservoir, further underscores the method's reliability. Post-optimization, NPV increases by 1.1 times, 1.4 times, and 0.34 times for the respective calculation cases compared to the initial plan. When applied to an actual shale oil reservoir, the method yields a 1.67 times increase in NPV compared to existing deployment plans. This research lays a solid theoretical foundation for the design of horizontal fracturing well construction plans in shale reservoirs.

Evolution features and a prediction model of casing perforation erosion during multi-staged horizontal well fracturing

Large-displacement high-intensity sanding hydraulic fracturing operations often cause casing perforation erosion and thus temporary plugging failures, exacerbate the unevenness of fracture initiation and expansion, and induce casing damage. In order to clarify the dynamic evolution of perforation erosion and predict perforation diameter, the effects of different types of proppants, the viscosity of sand-carrying liquids, and large sand-passing quantities on perforation erosion rate were experimentally explored in the study. The evolution of perforation erosion and the particle size distribution of quartz sand and ceramsite were analyzed in the experiment and a prediction model for perforation erosion under various fracturing parameters was established. Compared to ceramsite, quartz sand had the more significant effect on perforation erosion and the more serious particle abrasion and fragmentation under the same sand-passing quantity. Increasing the viscosity of the sand-carrying liquid slowed down perforation erosion and made the edge of perforation entrance more uniform. As the sand-passing quantity through the perforation increased, perforation erosion in the initial stage was concentrated at the perforation edge. Then, the inner wall of the perforation was also eroded, but the average erosion rate was reduced. A prediction model of perforation erosion considering multiple fracturing parameters was established based on the principle of fluid similarity. The errors between predicted values and downhole eagle-eye observation values were less than 15 %. The model provides an important basis for the optimization of fracturing parameters and downhole casing strength design.

Management of horizontal root fracture with root resorption at apical third using calcium silicate-based cement -A case report

Management of horizontal root fracture with root resorption at apical third using calcium silicate-based cement -A case report

Investigation on the effect of the relative position between fracture and injection-production well on thermal extraction performance

The development of hot dry rock (HDR) resources is mainly through hydraulic fracturing to build fracture in low permeability high-temperature rock to form working fluid flow channels. The control mechanism of thermal transfer and conversion process in fracture system is the key to influence thermal extraction effect. In this paper, a temperature-hydraulic-mechanical (THM) coupling model of fractured rock mass is established considering the temperature variation of rock elastic modulus and Poisson's ratio. The dynamic changes of fracture aperture and permeability are investigated. Taking fractured HDR reservoir as a case study, the depletion thermal extraction process of dual-well enhanced geothermal system (EGS) is simulated, the spatial-temporal evolution of multi-field are analyzed. The results show that the cold front of the horizontal and vertical single fracture model advance in an oval shape and a rectangle shape, respectively. Over 30 years, the horizontal fracture aperture typically changes by a factor ranging from 1.02 to 1.12, permeability typically changes by a factor ranging from 5 to 15. The vertical fracture aperture typically changes by a factor ranging from 1.02 to 1.14, permeability typically changes by a factor ranging from 10 to 25.

Development characteristics and controlling mechanism of different microfracture combinations in shale reservoir: A case study of silurian longmaxi formation in Weiyuan area

Fractures in organic-rich shale are important reservoir spaces and seepage channels of shale gas, and they are closely related to the gas-bearing properties of shale. The development characteristics and laws of fractures are of great significance in the exploration and development of shale oil and gas. This study examines organic-rich shales of the Wufeng–Longmaxi Formation in the Weiyuan area of the Sichuan Basin. On the basis of two-dimensional large-area multi-scale combination electron microscopy characterization and digital core platform technology, the development degree and distribution of different fractures are quantitatively characterized. The results show the following. (1) The shale of the Wufeng and Longmaxi formations developed a variety of fractures with different occurrences, sizes, and origins. According to the number and combination relationship between fractures of different occurrences, the shale can be divided into four fracture combination types: horizontal bedding fractures; vein fractures; reticular fractures; and ring fractures. Of these, the horizontal bedding fracture group has the largest number of samples and a higher average fracture surface porosity. (2) The degree of fracture development in the shale is affected by many factors, such as the laminar type, mineral composition, mineral particle size, mineral distribution, and total organic carbon, and the controlling mechanisms of different fracture combination types differ. Factors such as horizontal stratification, high clay mineral content, and uneven mineral particle size are conducive to the development of horizontal bedding joints. (3) Differences in the sedimentary environment affect the variation laws of the vertical fracture combination types and density. The total organic carbon and organic quartz content of the Long111 layer with deeper sedimentary water is higher, and the vein fracture formation is more developed than in other small layers, while the clay mineral content of the Long112 and Long114 layers with shallower sedimentary water is higher and the horizontal layer is more developed; the fracture combination type is dominated by the horizontal bedding fracture combination. At the same time, the fractures at the junction of each layer of the Long11 sub-member are the most developed because sea level rise and fall make the mineral particle size heterogeneity most prominent at the junction of the small layer.

Micromechanical variation of organic matter (kerogen type I) under controlled thermal maturity progression

Shale formations have recently gained plenty of attention owing to their large amounts of reserves. Horizontal drilling and hydraulic fracturing are the proposed approaches for the development of shale formations. The extended information of the mechanical properties of shale formation is crucial for designing a successful hydraulic fracturing operation. On the other hand, the mechanical properties of such organic-rich formations are greatly affected by the mechanical characteristics of the present kerogen (organic matter), which dramatically changes during the maturation process. In this study, a Qingshankou shale sample containing kerogen type I is mechanically investigated at different maturity levels using the grid nanoindentation approach. To this end, the original immature sample is artificially matured during hydrous (HP) and anhydrous (AHP) pyrolysis. More than 930 nanoindentation tests were performed on grids of 9 × 8 on the surface of 13 samples with different maturities. The test results showed that the presence of water during pyrolysis can significantly affect the shale sample’s mechanical characteristics. In higher temperatures and higher levels of maturity, the role of water becomes more pronounced. During hydrous pyrolysis, kerogen produces larger amounts of oil and bitumen, which become progressively porous. While the original sample showed a Young’s modulus value of more than 48 GPa, and it fluctuated between approximately 19 and 32 GPa during the HP scenario and between 17 and 34 GPa during the AHP process. In terms of hardness, the original sample exhibited an initial value of about 1.1 GPa and more mature samples reflected hardness values in the range of approximately 0.3 and 0.97 GPa in both scenarios. According to the trends of mechanical properties during maturation, mechanical properties decreased at the initial stage of maturation and remained relatively constant during the oil window. Then, another decline was detected at the wet-gas window’s closure. In the dry-gas window, HP and AHP scenarios exhibited different behaviors mainly due to the chemical structure of the kerogen residue.

Optimizing the preparation of multi-colored dye-tracer proppants: A potential approach for quantitative localization and volume assessment of proppant flowback in multistage fractured horizontal wells

Proppant flowback is a common phenomenon after hydraulic fracturing of oil and gas wells. Especially in the large-scale sanding mode of horizontal wells, sand production after fracturing is usually serious. Proppant flowback can not only clog wellbore and wear out equipment, add additional hauling and disposal costs, but also reduce conductivity of the propped fractures, severely affecting oil and gas production. However, there is still a lack of effective means for locating sand production in horizontal wells. Traditional tracer proppants mainly use radioactive elements to monitor the shape of fractures, but they cannot tell the location and amount of sand production. In this work, dye tracer proppant of eight different colors was prepared by dyeing quartz sand proppant. The results show that all the eight kinds of dyes can dye the quartz sand proppant effectively and evenly. The optimal ratio of proppant mass to MB solution volume was determined to be 1:0.015, and the ratio of proppant mass to fixing agent volume was 1:0.0125. The dyed tracer proppant showed good dyeing stability at pH values of 6–13 and surfactant concentrations of 0–200 mg/L. The salinity and fracturing fluid did not affect its stability, and temperature had a negative effect on the stain stability. However, even in the most severe case of decolorization in the experiment, that is, after the dyed proppant was soaked for 24 h at a high temperature of 120 °C, the color of the dried dyed proppant was still clearly distinguished from that of ordinary quartz sand. In theory, using these dyed proppants can potentially tell quantitively the location and volume of sand production during horizontal large-scale fracturing flowback. Since this method has not been used in hydraulic fracturing, it only provides a new way to monitor the sand production of horizontal wells after fracturing. It can provide valuable data for adjusting subsequent fracturing process and has important implications for improving efficiency of fracturing operation of unconventional oil and gas reservoirs.

Femtosecond laser ablation responses of kerogen-rich, argillaceous, and bituminous shale rocks

Shale rocks have become one of the major sources of natural gas and oil. Laser drilling has emerged as a promising technique that can be incorporated into horizontal drilling and hydraulic fracturing processes. In this study, we selected three types of shales (kerogen-rich, argillaceous, and bituminous) with distinct compositions and microstructures and performed femtosecond laser irradiation with different power and energy to investigate their ablation characteristics. Evidence of melting and solidification was observed in all samples, despite the ultra-high pulse frequency of the femtosecond laser. Among the three types of shale rocks, the kerogen-rich shale exhibited the highest ablation rate, while argillaceous and bituminous shale showed lower and comparable rates. The above observations highlight the significance of shale chemistry in influencing laser ablation characteristics under femtosecond laser irradiation. Furthermore, no ablation rate anisotropy was observed when irradiating the samples parallel with and perpendicular to the bedding direction, although shale rocks are microstructurally and mechanically anisotropic.

Method for predicting the injection pressure for horizontal wells in fractured tight sandstone reservoirs

Hydraulic fracturing and horizontal well drilling are the key technologies for increasing the production of continental tight sandstone reservoirs. Taking the typical fractured tight sandstone in the Yuan-287 block of the Ordos Basin as an example, a reservoir geologic model is established based on the stratigraphic correlation of 206 wells. The model and 3D paleostress field are combined to predict fracture parameters such as fracture density and strike. Using reservoir breakdown pressure (RBP) monitoring data and other data such as reservoir physical and mechanical parameters, tectonic fracture characteristics, and in situ stress parameters, a quantitative evaluation model of the RBP, which predicts the 3D distribution of RBP, is established via stepwise regression, and the factors controlling the RBP are analyzed. The rock P-wave velocity, horizontal minimum principal stress, and fracture density are found to be three key parameters that control the breakdown pressure of this tight sandstone reservoir. By comparing the fracture opening pressure of subsurface tectonic fractures with the RBP, a new method for predicting the optimal water injection pressure of this reservoir is developed. This work provides a valuable evaluation model for accelerating the efficient development of continental tight sandstone reservoirs.

Segmentation Study of Deep Shale Gas Horizontal Wells of the South Sichuan Shale Gas

Summary The low porosity and low permeability of shale gas reservoirs make fracturing technology an indispensable part of shale gas reservoir development. The initial stage of shale gas development is characterized by shallow direct wells, but with the advancement of drilling and completion technology in the development of unconventional oil and gas reservoirs, horizontal wells and fracturing technology have gradually become the key methods for the effective development of oil and gas reservoirs. “Geology-engineering integration” has gradually become a hot spot in the research of horizontal well fracturing. The factors affecting the development of shale gas reservoirs are subdivided into “geological sweet spot” and “engineering sweet spot” influencing factors. Geological sweet spot refers to the area where the reservoir is rich in hydrocarbons or organic matter; engineering sweet spot refers to the area with good fracturability in the later fracturing and reforming of the reservoir. The shale gas sweet spot area should have the characteristics of high gas content, high fracturable, and high efficiency. Comprehensively evaluating the physical properties and brittleness characteristics can provide certain guidance for shale gas horizontal well segmentation.

A Study on the Mechanism of Fracture Initiation and Propagation under Multi-Perforation Conditions in Hydraulic Fracturing

To reveal the mechanism of hydraulic fracture initiation and propagation under the conditions of multiple perforations during horizontal well fracturing, we creatively conducted dual-hole fracturing experiments on small rock samples and established a two-dimensional model of a single cluster with multiple perforations in a horizontal well based on the extended finite element method using the fluid–solid coupling equation, which was combined with the basic theory of damage mechanics. The biggest difference from previous research is that this model does not consider the hypothesis of stress shadows and only focuses on studying the initiation and propagation of multiple perforations in one cluster. We studied the effects of perforation parameters, stress state, and injection flow rate on the initiation and propagation of hydraulic fractures using this model. The experimental and simulation results indicate that under multi-perforation conditions, the number of fractures depends on the number of perforations. The simulation results show that when the spacing between perforations increases or the number of perforations reduces, the initiation time of perforation is advanced and the interference between fractures weakens, which is conducive to the initiation and propagation of hydraulic fractures. As the stress difference increases, the initiation time of perforation becomes earlier and the deflection angle of the outermost fractures becomes smaller, which is conducive to the parallel expansion of the fractures. Moreover, although this has little impact on the morphology of fractures with the rise in flow rate in simulation, it is beneficial for improving the initiation and propagation speed of fractures. The length of fractures also increases significantly at the same time point. In addition, both the experiments and simulations revealed that an increase in the flow rate could accelerate the initiation time of fractures. The proposed model can guide fracturing construction to optimize the design of perforation spacing during horizontal well fracturing, which can contribute to reducing development costs and improving the final production.

Permeabilities of Water–Oil Two-Phase Flow in Capillary Fractures with Different Wettabilities

The influence of wettability on the permeability performance of water–oil two-phase flow has attracted increasing attention. Dispersed flow and stratified flow are two flow regimes for water–oil two-phase flow in capillary fractures. The theoretical models of relative permeability considering wettability were developed for these two water–oil flow regimes from the momentum equations of the two-fluid model. Wettability coefficients were proposed to study the impact of wettability on relative permeabilities. Experiments were conducted to study the relative permeabilities of laminar water–oil two-phase flow in water-saturated and oil-saturated horizontal capillary fractures with different hydraulic diameters. These fractures were made of polymethylmethacrylate (PMMA) and polytetrafluoroethylene (PTFE), which had different surface wettabilities. In this experiment, the regimes are dispersed flow and stratified flow. The results show that the effect of wettability on the relative permeabilities increases as the hydraulic diameters of capillary fractures decrease for water–oil two-phase flow. The relative permeabilities in a water-saturated capillary fracture are higher than those in an oil-saturated capillary fracture of the same material. The relative permeabilities in a PTFE capillary fracture are larger than those in a PMMA capillary fracture under the same saturated condition. Wettability has little effect on the permeability performances of water–oil two-phase flow in water-saturated capillary fractures, but is significant for those in oil-saturated capillary fractures.

Study of geomechanical properties of the Pimienta formation with undrained multi-stage triaxial tests, Central-Western Tampico Misantla Basin, Mexico

The Pimienta Formation (J-Pi) of the Tampico Misantla Basin (TMB) in Mexico is known for its potential as unconventional onshore hydrocarbon reserves. The area of interest in this study is located in the western-central part of the TMB, where no significant production has been established from unconventional resources. Given the low permeability and low porosity characteristics of the carbonaceous mudstone in the Pimienta formation, it is necessary to implement techniques to increase the area of flow from the reservoir to the borehole, achieving profitable oil and gas extraction.The geomechanical properties of rock strata are essential inputs for the design and implementation of shale oil and gas production engineering, such as horizontal drilling and hydraulic fracturing. Understanding the capabilities of the rock to yield and contain hydraulic fractures is essential to designing safe and efficient well stimulations. Likewise, the wellbore stability is of critical importance to the successful development of secondary and tertiary recovery systems.In this study, core samples from the Pimienta Formation in the TMB are analyzed through undrained multi-stage triaxial tests, emphasizing the estimated in-situ geo stresses and the effect of the mineral composition of the rock. The geomechanical parameters of compressional strength, Poisson ratio (PR), and Young's modulus of the Pimienta formation are obtained from the analysis of the experimental data and finding correlations to the mineral composition of the samples. A detailed characterization is completed under the conventional rock mechanics methodologies of Mohr-Coulomb and Hoek-Brown failure criterion, as well as Brittleness Index (BI).

Shear wave anisotropy response characteristics of laminated shale and its correction methods

Laminated shale exhibits strong anisotropic characteristics in horizontal wells, significantly affecting the application of shear wave travel time data. Using equivalent medium theory and the elastic wave equation, we constructed a physical model for laminated shale, simulating the impact of lamination angle and lamination density on shear wave velocity and shear wave anisotropy coefficient. We established the relationship between the shear wave anisotropy coefficient and the cosine of the lamination angle. The simulation results indicate that shear wave velocity decreases with an increase in lamination angle and density, while the shear wave anisotropy coefficient gradually decreases with an increase in lamination angle and initially increases and then decreases with an increase in lamination density. Moreover, it exhibits a power exponential relationship with the cosine of the lamination angle. After correction, the minimum horizontal principal stress and fracture pressure calculated from shear wave data show an average relative error reduction of 6.72% and 7.77%, respectively, compared to measured data. This demonstrates that the correction method effectively eliminates the impact of laminated shale anisotropy on shear waves.

Application of '10 Keys' Checklist and Partial Extraction Techniques to Optimize Esthetic Outcome for Adjacent Implants in the Esthetic Zone.

Placing immediate implants in the esthetic zone area poses significant challenges. Implants should be placed with consideration to hard and soft tissue management to optimize long term implant and cosmetic success. In this case report, two maxillary central incisors were extracted in two different time points, separated by 5 years because of horizontal root fractures. Implants were placed according to immediate single-tooth guidelines, using two different surgical and loading approaches, as risk assessment factors changed in the time between first immediate placement (#8) and second immediate placement (#9). These techniques included Partial Extraction Therapy (PET), the use of allograft and growth factors, connective tissue graft (CTG), platelet rich fibrin (PRF) and immediate and conventional loading. These were grouped as the '10 keys', a checklist used to pursue long term success. After 6-year and 1-year follow-up, radiographic and clinical results were satisfactory.

Potassium permanganate oxidation of low-permeability phenanthrene contaminated soil under fracturing conditions

In situ chemical oxidation (ISCO) technology has limitations in the remediation of low-permeability polycyclic aromatic hydrocarbon (PAHs)-contaminated sites because of the difficulty in oxidant delivery. Horizontal fractures created by hydraulic fracturing provide convenient channels for rapid oxidant delivery. However, limited studies have focused on potassium permanganate (KMnO4) oxidation in low-permeability PAH-contaminated sites under fracturing conditions considering in situ hydrological environments. Therefore, this study aimed to explore the effect of KMnO4 concentration on the remediation efficiency (including the removal rate of phenanthrene (PHE), remediation time, and total oxygen demand (TOD)) of low-permeability PHE-contaminated soil through a one-dimensional penetration-oxidation test, and the effect of KMnO4 oxidation on the physicochemical properties of the soil through a series of laboratory experiments. The results showed that an increase in KMnO4 concentration shortened the remediation time and increased the removal rate of PHE and TOD from PHE-contaminated soil. The oxidation of KMnO4 resulted in an increase in the pH, oxidation-reduction potential, dissolved organic carbon, cation exchange capacity, specific surface area, and fine particle content of the soil, and a decrease in the total organic carbon of the soil, but did not alter the permeability of the soil.

Seismic wave modeling of fluid-saturated fractured porous rock: including fluid pressure diffusion effects of discretely distributed large-scale fractures

Abstract. The scattered seismic waves of fractured porous rock are strongly affected by the wave-induced fluid pressure diffusion effects between the compliant fractures and the stiffer embedding background. To include these poroelastic effects in seismic modeling, we develop a numerical scheme for discretely distributed large-scale fractures embedded in fluid-saturated porous rock. Using Coates and Schoenberg's local-effective-medium theory and Barbosa's dynamic linear slip model characterized by complex-valued and frequency-dependent fracture compliances, we derive the effective viscoelastic compliances in each spatial discretized cell by superimposing the compliances of the background and the fractures. The effective governing equations for fractured porous rocks are viscoelastic anisotropic and numerically solved by the mixed-grid-stencil frequency-domain finite-difference method. The main advantage of our proposed modeling scheme over poroelastic modeling schemes is that the fractured domain can be modeled using a viscoelastic solid, while the rest of the domain can be modeled using an elastic solid. We have tested the modeling scheme in a single fracture model, a fractured model, and a modified Marmousi model. The good consistency between the scattered waves off a single horizontal fracture calculated using our proposed scheme and the poroelastic modeling validates that our modeling scheme can properly capture the fluid pressure diffusion (FPD) effects. In the case of a set of aligned fractures, the scattered waves from the top and bottom of the fractured reservoir are strongly influenced by the FPD effects, and the reflected waves from the underlying formation can retain the relevant attenuation and dispersion information. The proposed numerical modeling scheme can also be used to improve migration quality and the estimation of fracture mechanical characteristics in inversion.

Fluid inclusion evidence for overpressure-induced self-sealing and accumulation of deep shale gas

Shale oil and gas exploration and development are extending to greater depths, and it is important to understand the accumulation mechanisms of shale oil and gas. Here we conducted a case study in the Upper Ordovician Wufeng Formation–Lower Silurian Longmaxi Formation in the Ningxi area, Sichuan Basin, southwest China, by using petrological and fluid inclusion investigation to determine the processes involved during the overpressure-induced self-sealing accumulation of deep shale gas. Results show that fibrous quartz–calcite veins in the source rocks contain abundant gas inclusions and coeval two-phase gas–liquid aqueous inclusions. The gas inclusions are relatively uniform, translucent to transparent, single-phase inclusions with a high density, indicative of a closed shale system. The gas inclusions record varying levels of fluid overpressure (115.23–169.46 MPa), with a paleo-pressure coefficient of 2.12–2.98. Fluid overpressure and self-sealing resulted in shale gas accumulation, with bedding-parallel and laminar fractures acting as important migration pathways, which improved the horizontal porosity and permeability of the shale. These processes are common and important phenomena in petroleum systems. Unconventional oil and gas development commonly requires horizontal fracturing of wells to form a fracture network, which can improve the production capacity.