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Radial borehole fracturing is a production method that combines ultrashort radius radial boreholes with hydraulic fracturing, which is expected to effectively improve the drainage and transformation effect of tight oil and gas reservoirs. In view of the problem that radial boreholes cannot be fully fractured when high-pressure liquids are injected into them simultaneously, this paper proposes a new method of fracturing the radial boreholes step by step, and this method is verified by the laboratory fracturing experiments. It designed and processed wellbores with both internal and external pipes, conducted 24 sets of radial boreholes step-by-step experiments of double-layer radial boreholes, analyzed the reproducibility of the experimental results, and compared the results of fracturing radial boreholes simultaneously and fracturing radial boreholes step-by-step experiments. The results show that this method can fracture two sets of radial boreholes distributed in different vertical planes. The results demonstrate that this method is feasible and can solve the problem that not all the radial boreholes are fractured when fracturing fluids are simultaneously injected into them. Besides, the azimuth is the key factor affecting fracture geometries. When the azimuths are 0° and 30°, the fractures can cut through radial boreholes in different layers within the rock samples. If the radial boreholes with larger azimuths are fractured, it will generate higher breakdown pressures. Fracturing radial boreholes with smaller azimuths first and then radial boreholes with larger azimuths should be selected. This study provides a theoretical basis for the field application of radial borehole fracturing technology. Highlights: A new method of fracturing the radial boreholes step by step is proposed. The azimuth is the key factor affecting fracture geometries. If the radial boreholes with larger azimuths are fractured, it will generate higher breakdown pressures. [ABSTRACT FROM AUTHOR]

During oil and gas reservoir development, multi-stage horizontal wells (MFHWs) and hydraulic fracturing techniques can effectively increase estimated ultimate recovery. However, there still lacks an understanding of the three-dimensional (3D) pressure transient behaviors of multi-stage fractured horizontal wells with secondary fractures. To narrow this gap, a three-dimensional numerical well-test model based on a discrete fracture model and unstructured tetrahedral grids is developed to study the pressure transient behaviors of MFHWs with secondary fractures. The pressure transient solutions of MFHWs with secondary fractures have been demonstrated by model verifications. The results show that the proposed model can accurately capture the complex transient flow around fractures, including early radial flow that is not easily captured by two-dimensional numerical well test models. The proposed model classifies the flow regimes of a MFHW as: wellbore storage and skin effects, early radial flow, bilinear flow, linear flow, elliptical flow, pseudo radial flow, and pseudo-boundary dominated flow. It is found that the fracture geometry has a relatively large effect on the shape of the pressure derivative curve in this work. The hydraulic fracture half-length has the greatest impact on the pressure transient behaviors of the MFHW, followed by fracture height and secondary fracture half-length, as found in this study. Additionally, fracture parameters are evaluated, and actual well testing data are interpreted, taking into account the fracture height. This work is meaningful to understand the three-dimensional pressure transient behaviors of MFHWs with secondary fractures. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing is widely recognized as a potential stimulation technology for the development of challenging natural gas hydrate. However, the fracturing behavior of non-diagenetic hydrate reservoirs has peculiar characteristics that are different from those of conventional oil and gas reservoirs. Herein, a fully coupled fluid-mechanical model for simulating hydraulic fracturing in hydrate-bearing sediments (HBS) was established based on the discrete element method, and the influence of hydrate saturation, in situ stress, and injection rate on the meso-fracture evolution was investigated. The results indicate that with the increase in hydrate saturation, the fracture morphology transitions from bi-wing to multi-branch, thereby enhancing fracture complexity. Both tensile and shear failure modes exist, and the tensile failure between the weakly cemented sediment particles is dominant. The tensile strength of HBS is an exponential function of hydrate saturation, with the breakdown pressure being governed by hydrate saturation and in situ stress, with the form being consistent with the classical Kirsch equation. Additionally, lower in situ stress and higher injection rates are conducive to the generation of microcracks, whereas an excessive injection rate reduces the fracture length. These findings contribute to understanding the meso-evolution mechanism of hydraulic fractures and guide the design of on-site hydraulic fracturing plans of natural gas hydrate reservoirs. [ABSTRACT FROM AUTHOR]

The pattern of placement of the proppant in the fracture determines the stimulation and success of the surgery. Using a three‐dimensional visual parallel plate fracture model capable of simulating fracture height, length, and variable fracture width, we experimentally investigate the impact of fiber loading, fracture fluid viscosity, sand concentration, pulse time, perforation pattern, and injection rate on proppant transport, placement pattern, and access rate. Experimentally and visually, the migration process and the morphology of the proppant placement in the fracture were assessed. The formation laws of stable support columns and well‐shaped high conductivity fracture channels in fractures have been elucidated. Experimental results show that increasing the fiber concentration improves the channel rate and the proppant mass is large and stable. The channel rate increases with the viscosity of the fracturing fluid, and it is difficult to form a perfect channel when the viscosity is small. If the constructive displacement is too slight or too large, it will not favor the formation of a Hi‐way channel in the fracture. The optimal design displacement is 4.5 m3/min. When the proppant concentration is low, the passage rate is large, but the stability of proppant mass is poor under the scour of large displacement, the conductivity is low under the high closure pressure, the proppant concentration is too high, the suspension is difficult, the settlement rate is large, and it is difficult to form a large passage. The current column and the passage rate are larger for pulse times of 15–20 s. Cluster perforations are better than large continuous perforations. The higher the number of clusters in the same number of holes, the higher the channel rate. The formation laws of stable support pillars and well‐shaped high conductivity fracture channels in fractures have been elucidated, which can be useful for efficient stimulation of oil and gas reservoirs. [ABSTRACT FROM AUTHOR]

With the continuous exploration and development of unconventional oil and gas reservoirs, volume fracturing technology becomes one of the necessary measures for developing shale gas and tight sandstone gas reservoirs effectively. Volume fracturing technology usually uses slickwater and drag-reducing agent as the core of the fracturing system. The composition of the fracturing system is the main factor determining its performance. Polyacrylamide has many amide groups in its main chain, high activity, and controllable performance, often in solid powder and liquid emulsion states. Furthermore, polyacrylamide which is the water-soluble drag-reducing agent is most widely used in applying current shale gas slickwater fracturing operations. Due to the low viscosity and poor sand-carrying capacity of slickwater, proppant easily settles at the bottom of hydraulic fractures. This phenomenon influences the stimulation effect of volume fracturing. Therefore, the law of sand carrying and placement of proppant in hydraulic fractures in volume fracturing plays an essential role in determining the success of the stimulation effect of volume fracturing. Through the visualization device of proppant transport in the fracture, the settlement of proppant in the fracture was studied experimentally. And through experimental equipment, the effects of different operation pumping rates, liquid viscosity, proppant type, and proppant pumping schedule on the stimulation effect were studied. The experimental results can provide strong support for volume fracturing into well material optimization and operation parameter optimization for unconventional oil and gas reservoirs. [ABSTRACT FROM AUTHOR]

With the continuous exploration and development of unconventional oil and gas reservoirs, volume fracturing technology becomes one of the necessary measures for developing shale gas and tight sandstone gas reservoirs effectively. Volume fracturing technology usually uses slickwater and drag-reducing agent as the core of the fracturing system. The composition of the fracturing system is the main factor determining its performance. Polyacrylamide has many amide groups in its main chain, high activity, and controllable performance, often in solid powder and liquid emulsion states. Furthermore, polyacrylamide which is the water-soluble drag-reducing agent is most widely used in applying current shale gas slickwater fracturing operations. Due to the low viscosity and poor sand-carrying capacity of slickwater, proppant easily settles at the bottom of hydraulic fractures. This phenomenon influences the stimulation effect of volume fracturing. Therefore, the law of sand carrying and placement of proppant in hydraulic fractures in volume fracturing plays an essential role in determining the success of the stimulation effect of volume fracturing. Through the visualization device of proppant transport in the fracture, the settlement of proppant in the fracture was studied experimentally. And through experimental equipment, the effects of different operation pumping rates, liquid viscosity, proppant type, and proppant pumping schedule on the stimulation effect were studied. The experimental results can provide strong support for volume fracturing into well material optimization and operation parameter optimization for unconventional oil and gas reservoirs. [ABSTRACT FROM AUTHOR]

Viscoelastic surfactant fracturing fluids, also known as clean fracturing fluids, have attracted extensive attention in the field of hydraulic fracturing because of their advantages, such as complete gel breaking, no residues, and low formation damage. However, the complex synthesis process, high cost, and the inability to reuse have limited the practical application of clean fracturing fluids. Herein, a pH-responsive clean fracturing fluid with pH-regulated apparent phase and rheological behaviors was constructed based on the mechanism of pseudo-trimeric surfactant and wormlike micelles formed under specific pH conditions by N,N-dimethyl oleoaminde-propylamine and tricarballylic acid. The results show that the zero-shear viscosity of the fracturing fluid can reach more than 111.2 Pa·s, and it can switch between a high-viscosity gel state and a low-viscosity aqueous solution state more than four times by adjusting pH. The constructed clean fracturing fluid is suitable for medium and low-temperature oil and gas reservoirs. The viscosity of the fracturing fluid is still higher than 500 mPa·s after shearing at 60 °C and 170 s−1 for 60 min. In addition, the fracturing fluid can be completely broken within 1 h, and the gel broken-fluid has low viscosity and no residues. [ABSTRACT FROM AUTHOR]

The discrete fracture networks (DFN) have become indispensable tools for geomechanical modelling of jointed rock masses. The technology creates a three-dimensional (3D) representation of fracture geometry used in the construction of surface and subsurface engineering projects in mining, civil engineering, and fracturing of the reservoir in the oil and gas industry. The approach depends on the accuracy of the data obtained during site investigation to create models that represent the fracture geometry of the structure. The better the acquired information available, the better the stochastic analysis that determines the engineering applications and designs that can be carried out. Therefore, it is important to use instruments that can capture fracture distribution characteristics such as fracture intensity, fracture orientation, spatial distribution, fracture length, fracture aperture, and size. This study provides a detailed review of the recent advances in the application of a DFN for modelling jointed rock masses in different engineering applications. The paper shows the principles of modelling in a DFN, including various data-capturing methodologies, and the general application of DFN in various fields. Several case studies where the DFN method was applied are presented in the paper. These include evaluation of slope in an open pit mine, modelling of discontinuity in tunneling, stability evaluation of coal seam longwall, the design of high-level radioactive waste, prediction of groundwater flow, fracturing of petroleum reservoirs, and geothermal cracking of shale gas in the coal bed. However, despite the versatility of the DFN technique, there are still some limitations and challenges to the integration of complexities encountered in rock masses within DFN models. [ABSTRACT FROM AUTHOR]

Massive hydraulic fracturing (MHF) is currently the most effective technology used to create fracture networks with sufficient conductivity and maximize the stimulated reservoir volume (SRV) in tight oil and gas reservoirs. The newly initiated fracture networks during MHF usually exhibit complex fracture morphology and contain intersected fractures and fracture branches. The conductivity of these fractures plays a pivotal role in determining long-term productivity. Due to the complex geometry, it is difficult to accurately evaluate intersected fracture conductivity through traditional conductivity measurement methods and devices which are designed for a single primary fracture. Unlike previous studies where fracture conductivity was measured using two rock slabs under single-direction (vertical) loading, we establish a novel conductivity measurement apparatus that can mimic different fracture intersection scenarios under both vertical and transverse loading to facilitate the evaluation of intersected fracture conductivity. Based on this apparatus, a standard conductivity measurement framework for intersected fractures under biaxial compaction conditions is also proposed, and stable and reliable conductivity testing data are obtained. Sensitivity analyses are performed to find out the controlling factors of intersected fracture conductivity and the corresponding conductivity evolution law. Results indicate that the overall intersected fracture conductivity of intersected fractures can be divided into three stages, with closure pressure increasing, videlicet, the conductivity rapid reduction stage at low closure pressure, the conductivity slow reduction stage, and the conductivity stabilization stage. Higher proppant concentration results in higher conductivity. However, the conductivity differences among cases with different proppant concentration are relatively small at high closure pressure (conductivity stabilization stage). The more complex the fracture intersecting pattern is, the higher the conductivity would be. The experimental results can provide guidance for the design of proppant placement procedure for intersected fractures. [ABSTRACT FROM AUTHOR]

Multi-well hydrofracturing is an important technology for forming complex fracture networks and increasing reservoir permeability. The distribution and design of horizontal wells affect fracture propagation; however, it is still unclear how the spacing between adjacent wells leads to fracture propagation, deflection and connection. In this study, the thermal-hydro-mechanical coupling effect in the hydrofracturing process is comprehensively considered and a multi-well hydrofracturing model based on the finite element–discrete element method is established. Using typical cases, the unstable propagation of hydraulic fractures in multiple horizontal wells under varying adjacent well spacings is studied. Combined with the shear stress shadow caused by in situ stress disturbed by fracture tip propagation, quantitative indexes (such as length, volume, deflection and unstable propagation behaviors of hydrofracturing fracture networks) are analyzed. The results show that the shear stress disturbance caused by multiple hydraulic fractures is a significant factor for multi-well hydrofracturing. Reducing well spacing will increase the stress shadow area and aggravate the mutual disturbance and deflection between fractures. The results of quantitative analysis show that the total length of hydraulic fractures decreases with the decrease of well spacing, and the total volume of hydraulic fractures increases with the decrease of well spacing. The results of unstable propagation and stress evolution of hydraulic fracture networks considering thermal-hydro-mechanical coupling obtained in this study can provide useful guidance for the valuation and design of hydrofracturing fracture networks in deep unconventional oil and gas reservoirs. [ABSTRACT FROM AUTHOR]

In order to maximize the production of unconventional oil and gas reservoirs, the well spacing has been shrinking continuously. Thus, the interwell fracturing interference usually occurs, which brings some problems affecting the fracturing efficiency. As one of the most challenging issues, a set of efficient methods for diagnosing wellhead pressure characteristics of interwell fracturing interference need to be established. In this study, taking the shale oil well platform of Lucaogou Formation as an example, the wellhead pressure resulted from interwell fracturing interference was analyzed. A real-time diagnosis method for each fractured stage based on the power-law model was proposed; the interference was further classified into four types. Meanwhile, the parameters of well spacing and completion were optimized. The results show that the power-law model of nonuniform pressure transmission in complex fracture networks is applicable for the evaluation of wellhead pressure fluctuation in real time. According to the differential pressure, the differential pressure derivative and the variation range of pressure interference during fracturing (PIF) and the interwell fracturing interference of Lucaogou Formation shale oil can be classified into pressure communication type (I), hydraulic fractures connected type (II), large natural fractures interconnected type (III), and composite type (IV). Specifically, the type of III and IV will do harm to the production, while the type of I is conducive to supplementing formation energy. The type of II may be conducive to supplementing formation energy in some situations. The well spacing of shale oil in the Lucaogou Formation is preferably 150~200 m, and the injection rate is optimized to 12 m3/min. The findings of this study can help for better understanding of identifying wellhead pressure characteristics of interwell fracturing interference and optimizing well spacing and completion parameters. [ABSTRACT FROM AUTHOR]

Proppant concentration and fracture surface morphology are two significant fractures that can affect proppant transport and deposition behavior especially in tight and oil and gas reservoirs. This paper proposed a new set of similarity criteria for proppant experimental design by incorporating proppant concentration and fracture roughness. Based on the proposed criterion, proppant transport experiments in hydraulic fractures of tight oil and gas reservoirs were conducted to explore the proppant placement behavior and identify the key parameters that affected the fracture propping efficiency. Results showed that the proposed similarity criterion can be used to evaluate the onsite proppant transport behavior and optimize hydraulic fracturing parameters. Results showed that the fracture placement efficiency of LD C7 tight oil reservoir is mainly affected by sand ratio and fracturing fluid viscosity. The sand ratio in the LD C7 tight oil reservoir should not be less than 8%, and the optimal carrying fluid viscosity is 5 mPa s. The proppant placement efficiency of the SLG H8 tight gas reservoir is mainly affected by the displacement rate and frac fluid viscosity. The displacement rate of SLG H8 tight gas reservoir should not be less than 3.5 m3/min, and the optimal carrying fluid viscosity is 15 mPa s. [ABSTRACT FROM AUTHOR]

Multi-well pad fracturing is an indispensable technology for the sustainable development of unconventional oil and gas reservoirs, but the integrated simulation of fracture propagation and proppant migration in massive fracturing treatments remains challenging, including complicated numerical implementations and computational bottlenecks due to its multi-physics, fracture front propagation, size differences between proppant particles and hydraulic fractures. In this work, an integrated model of fracture propagation and proppant migration in multi-well pad fracturing was established based on the three-dimensional discontinuous displacement method for fracturing deformation computations and the Eulerian-Eulerian framework for capturing proppant concentration. The proposed simulator not only accounts for key physical processes such as stress shadow, dynamic flow rate distribution in the wellbore, fluid leak-off, perforation erosion, fractures evolution, proppant bridging, and gravitational settling, but also couples the simulation of 3D planar propagating fractures and proppant transport at well-pad scale, and presents excellent computational efficiency and promising applications than conventional fracturing models. To explore the fracture geometries and proppant distribution in typically stacked layers, single-well, multi-lateral wells, and multi-well pad fracturing are simulated from simple to complex. The findings showed that fracture propagation is jointly affected by intra-stage, inter-stage, and inter-well stress interference mechanisms, and fracture geometries are characterized by unevenness, asymmetry, and heel bias. Proppant transport is controlled by the fracture width and geometries, and most of the proppant is concentrated near the wellbore area and bridging at the narrow fractures. Fracture geometries and proppant distribution are sensitive to the landing locations of horizontal wells because hydraulic fractures always grow in the path of least resistance. Although close lateral well-spacing is beneficial to improve the stimulation efficiency, there are some challenges such as overlapped SRV, enhanced inter-well interference, and severe fracturing hits. Compared with the layout of stacked wells, staggered wells are not only beneficial to reduce the vertical inter-well interference, but also improve reservoir stimulation efficiency. Overall, the stimulated area of the high in-situ stress layers is relatively low even with intentionally landed wells. [ABSTRACT FROM AUTHOR]

Perforation hydraulic fracturing plays a crucial role in the development of oil and gas reservoirs, and perforation layout can significantly affect the initiation and propagation of complex reservoir rock fractures. In this paper, we used a mixed finite-discrete element method with an explicit iterative scheme called the continuous–discontinuous element method (CDEM) to study the process of hydraulic fracture propagation through perforation. The coupling effects of fluid flow and reservoir mechanics are fully considered, and the accuracy of the model in simulating the directional propagation of perforation hydraulic fractures is validated by comparison with physical experimental results. We also discussed in detail the impact of perforation pattern, density, depth, and aperture on crack initiation, propagation, and complexity, and used the new index of fracture degree to quantitatively evaluate the fracturing effects under the influence of multiple perforation layout parameters. The results indicate that: (i) hydraulic fractures near the wellbore compete for initiation, and the length distribution of cracks is uneven and intricate; (ii) linear perforation patterns produce the maximum initiation pressure, which is negatively correlated with the perforation density and positively correlated with the perforation depth and aperture; (iii) the fracture degree is mainly affected by perforation density and depth, and is less affected by aperture. Perforation can effectively control the fracture morphology and initiation pressure, and has a substantial influence on the crack propagation layout near the wellbore. This study provides a basis for the rational selection and optimization of perforation parameters, which can effectively improve the fracturing effects of tight oil and gas reservoirs. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing technology has become a key technology for the development of low-permeability/tight oil and gas reservoirs. The evaluation on the postfracturing effect is imperative to the formulation and implementation of the fracturing and development plan. Based on the characteristics of the flow in fracture network after a large-scale hydraulic fracturing, a numerical method for evaluating the effect of fracturing in vertical well was established. This study conducts postfracturing effect evaluations to block C Oilfield's wells that underwent conventional fracturing and volumetric fracturing, respectively, proposes the definition of fracture network conductivity and its relationship with cumulative production, and analyzes the fracturing construction parameters. The results suggest that the conventional fracturing can only form a single fracture instead of a stimulated reservoir volume (SRV) region. However, the volumetric fracturing transformation can form a complex fracture network system and SRV region and meanwhile bring obvious increase in the production. The effective time lasts for a longer period, and the increase of average daily oil is 2.2 times more than that of conventional fracturing. Additionally, with the progress of the production, the SRV area within the core region of the volume transformation gradually decreased from 6664.84 m2 to 4414.45 m2; the SRV area of the outer region decreased from 7913.5 m2 to 5391.3 m2. As the progress develops, the equivalent permeability and the area of the fracture gradually decrease as the fracturing effect gradually weakens, and so does the conductivity of the network decreasing exponentially; a good correlation is observed between the conductivity of the fracture network, the cumulative production, and fracturing construction parameters, which can serve as the evaluation parameters for the fracturing effects and the basis for fracturing productivity prediction and provide a guidance for fracturing optimization design. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing technology is the main method used to form high-conductivity fracture networks in unconventional oil and gas reservoirs, and the effective filling of quartz sand proppant in the fracture network is key to its successful implementation. Conventional experiments on the evaluation of sand carrying migration are mainly based on the migration and sedimentation law of a single-mesh proppant in the main fracture; the results obtained are inconsistent with the field observations. To improve our understanding of the migration and sedimentation law of the proppant in the main and branch fractures, in this study, the influences of injection time, injection rate, fracturing fluid viscosity, and proppant combination type on the migration and sedimentation law of a proppant in single and branch fractures were analyzed based on the injection parameters of the sand-carrying fracturing fluid obtained using a similarity criterion through a visual large-scale parallel-plate fracture model system built indoors. The results showed that the rapid accumulation stage of the proppant in the fracture is during the injection time of 5–10 min; the injection rate affected the accumulation area and height of the proppant to a certain extent but had little effect on the final sand dike morphology. A low viscosity of the fracturing fluid was not conducive to the sedimentation of the proppant in the branch fractures; an excessively high fracturing fluid viscosity was not conducive to the sedimentation of the proppant in both the main and branch fractures. When the fracture morphology is single, the viscosity of the fracturing fluid is recommended to be between 30 and 60 mPa·s. When the fracture morphology is complex, the recommended value is between 40 and 50 mPa s. Taking the migration and sedimentation laws of the proppant in the main fracture as an example, the flow of fracturing fluid in the fracture after the formation of a stable sand dike could be divided into five regions: ① inlet scour zone; ② buffer zone; ③ sand dike stable transition zone; ④ sand dike stability zone; and ⑤ outlet scour zone. The higher the large mesh proppant ratio used in the fracturing fluid, the lower the total area ratio of the corresponding sand dike; however, the proppant sedimentation ratio in the branch fracture increases. This study enriches and improves the relevant theoretical research on the migration and sedimentation of proppants and has a certain effect on improving the success rate of the hydraulic fracturing technology applied to unconventional oil and gas reservoirs. [Display omitted] [ABSTRACT FROM AUTHOR]

The use of degradable polymer materials as controlling additives to the working fluid during hydraulic fracturing is an area of interest in developing stimulation technologies. A temporary plugging agent with high compressive strength is used to block pre-fracturing or natural cracking and to initiate new fracture joints in order to increase the oil and gas passages, thereby realizing a stable production of oil and gas reservoirs. The temporary plugging agent prevents the fluid from entering the existing cracks, allowing the fracturing fluid to create new cracks and a more complex network of fractures within the reservoir. Considering the technological requirements, the temporary plugging agent must have a strong pressure resistance, good water solubility, and good returning performance, which can make new and old cracks simultaneously effective. In this paper, a new type of internal temporary plugging agent is developed, and the temporary plugging mechanism is evaluated through experiments, including plugging material microstructure, particle size, water absorption, water absorption speed, temporary plugging effect, and conductivity after dissolution. Our study shows that the temporary plugging agent provides a good temporary plugging effect, causes no pollution to the oil well, and can play a good protective role on the reservoir in repeated fracturing. [ABSTRACT FROM AUTHOR]

Summary: The hydraulic fracturing technique has been widely applied in many fields, such as the enhanced geothermal systems (EGS), the improvement of injection rates for geologic sequestration of CO2, and for the stimulations of oil and gas reservoirs. The key points for the success of hydraulic fracturing operations in unconventional resources are to accurately estimate the redistribution of pore pressure and stresses around the induced fracture and predict the reactivations of preexisting natural fractures. The pore pressure and stress regime around hydraulic fracture are affected by poroelastic and thermoelastic phenomena as well as by fracture opening compression. In this work, a comprehensive semi‐analytical model is used to estimate the stress and pore pressure distribution around an injection‐induced fracture from a single well in an infinite reservoir. The model allows the leak‐off distribution in the formation to be three‐dimensional with the pressure transient moving ellipsoidically outward into the reservoir from the fracture surface. The pore pressure and the stress changes in three dimensions at any point around the fracture caused by poroelasticity, thermoelasticity, and fracture compression are investigated. With Mohr‐Coulomb failure criterion, we calculate the natural fracture reactivations in the reservoir. Then, two case studies of constant water injection into a hydraulic fracture are presented. This work is of interest in the interpretation of microseismicity in hydraulic fracturing and in the estimation of the fracture spacing for hydraulic fracturing operations. In addition, the results from this study can be very helpful for the selection of stimulated wells and further design of the refracturing operations. [ABSTRACT FROM AUTHOR]

Estimation of in-situ stresses has significant applications in earth sciences and subsurface engineering, such as fault zone studies, underground CO2 sequestration, nuclear waste repositories, oil and gas reservoir development, and geothermal energy exploitation. Over the past few decades, Diagnostic Fracture Injection Tests (DFIT), which have also been referred to as Injection-Falloff Tests, Fracture Calibration Tests, and Mini-Frac Tests, have evolved into a commonly used and reliable technique to obtain in-situ stress. Simplifying assumptions used in traditional methods often lead to inaccurate estimation of the in-situ stress, even for a planar fracture geometry. When a DFIT is conducted in naturally fractured reservoirs, the stimulated natural fractures can either alter the effective reservoir permeability within the distance of investigation or interact with the hydraulic fracture to form a complex fracture geometry, this further complicates stress estimation. In this study, we present a new pressure transient model for DFIT analysis in naturally fractured reservoirs. By analyzing synthetic, laboratory and field cases, we found that fracture complexity and permeability evolution can be detected from DFIT data. Most importantly, it is shown that using established methods to pick minimum in-situ stress often lead to over or underestimates, regardless of whether the reservoir is heavily fractured or sparsely fractured. Our proposed "variable compliance method" gives a much more accurate and reliable estimation of in-situ stress in both homogenous and naturally fractured reservoirs. By combining the unique pressure signatures associated with the closure of natural fractures, a lower bound on the horizontal stress anisotropy can be estimated. [ABSTRACT FROM AUTHOR]

• The study reveals peculiar capabilities of global embedment of cohesive zone in deciphering complex fracture development pattern in highly jointed rocks. • Joint junctions approached by fracturing fluids are shown to be induced to slip phenomena that contribute to altering total slip behavior of surrounding rock body. • Low coefficients of friction in highly jointed rocks results in reduced the total slip of the entire medium compared to the scenario with high friction coefficients. • Moderate viscosity improves stimulated reservoir dimensions and increased injection rate favours opening of more compressed fractures. • This study is important for understanding fracture development complexity in soft jointed rocks together with associated slip phenomena. Complexity of fracture development in low permeability oil and gas reservoirs is of interest to many field operators for production enhancement. In highly jointed shales such as Marcellus and Sanmin, fluid-induced shear slip deformation along joint junctions coupled with soft nature of shale fabrics make fracturing operations more complicated. Sophistication includes widely reported occurrences of seismic tremors. Understanding of slip phenomena and fracture network development in such scenarios is never straightforward and curtailed with limited lines of evidence. In this study, we propose a globally embedded cohesive zone modelling within an elastoplastic three-dimensional framework to provide an understanding of the complex fracture development in soft shale formations. Shear strength of the global pore pressure cohesive elements is obtained as a function of field variable (stress) through parallel computation with FORTRAN language. Drucker Prager frictional behavior is included in the model with different friction coefficients to ascertain the joint slip phenomena when shear strength of the joints is reduced under the drenched effect of fracturing fluid. Results indicate that when the coefficient of friction is high, the total slip of the rock is reduced compared to the scenario with low friction coefficients. Other parametric analyses indicate that an isotropic stress regime leads to a more complex fracture development, while increased injection rates favour the opening of more compressed fracture wings. The model is validated against field data from layered shale reservoir as well as against Kristianovich-Geertsma-de Klerk (KGD) model with excellent agreements in both cases. This study is important for understanding fracture development complexity in soft jointed rocks together with associated slip phenomena. [ABSTRACT FROM AUTHOR]

Gas hydrate is undoubtedly an essential resource for sufficient energy supply (natural gas) in the near future. Unfortunately, low production efficiency limits its effective development and utilization. Hydraulic fracturing is a common and effective engineering measure to stimulate oil and gas reservoirs, as well as enhance oil recovery. However, its feasibility for clayey silt hydrate-bearing sediments is unclear now. What is more, there is no scientific basis for determining or assuming the value of fracture conductivity used in productivity prediction. In the present work, factors affecting conductivity of fractures in hydrate-bearing sediments were explored first. The experimental results showed that the conductivity of fracture in hydrate-bearing sediments was lower than 50 μm2·cm. Besides, it was found that the increase of proppant size, proppant concentration and hydrate saturation can improve the fracture conductivity. However, to achieve a similar effect, the closure pressure needs to be reduced appropriately. Based on these experiment results, the multi-factor influence model of fracture conductivity in hydrate-bearing sediments was developed. The conductivity profile at site SH2 in the northern South China Sea was then obtained. Finally, feasibility and efficiency evaluation of fracturing operation in hydrate reservoir was numerically conducted. The investigation results reveals that fracturing operation can greatly promote hydrate dissociation and gas production in hydrate development process. In addition, the importance of accurately determining fracture conductivity in productivity prediction of hydrate reservoir was also explored. It was found that gas production is only 12.11 × 108 m3 when fracture conductivity is 5.0 μm2·cm. However, it was as high as 22.82 × 108 m3 when fracture conductivity is 40 μm2·cm, which is 1.88 times that of the former case. The present work provides new perspective for design and optimization of fracturing operation in hydrate-baring sediments. • Factors affecting fracture conductivity in hydrate-bearing sediment was measured. • Model of fracture conductivity considering influence of multiple factors was developed. • Fracture conductivity profile at site SH2 in Shenhu area was determined. • Feasibility of fracturing operation in hydrate-bearing sediments was evaluated. • Importance of accurately determining fracture conductivity was explored. [ABSTRACT FROM AUTHOR]

The potential of commercial deployment of CO 2 sequestration in unmineable coal seams, as a measure to mitigate the greenhouse gas effect, has been tested through a series of small- to medium-scale CO 2 injection projects in the Appalachian Basin, USA. Essential tools for these projects are reservoir simulations in which the involved processes, prior to injection field tests are modeled to enhance understanding and to be used as a decision tool. Due to the large number of modeling input parameters and the high uncertainty in determining their values, an initial model sensitivity analysis of the key input parameters is required for the development of representative models. In this paper, preliminary single-well reservoir parametric simulations were conducted to identify how the variation of selected reservoir parameters and properties affect model results. More specifically, this sensitivity analysis focused on three areas: a) the effect of selected initial conditions (adsorption isotherm, fracture and matrix porosity, reservoir pressure, desorption time, water saturation and permeability), b) the influence of the production mechanism (permeability, face to butt cleat ratio, relative permeability, Langmuir volume, matrix and fracture porosities, desorption time, water saturation, initial reservoir pressure, and pressure gradient), and c) the contribution of the well characteristics (skin factor, explicitly defined hydraulic fractures and high permeability zones). This modeling work forms the basis for calibrating reservoir models used in simulations of CO 2 injection. [ABSTRACT FROM AUTHOR]

Downhole microseismic data has the significant advantages of high signal‐to‐noise ratio and well‐developed P and S waves and the core component of microseismic monitoring is microseismic event location associated with hydraulic fracturing in a relatively high confidence level and accuracy. In this study, we present a multidimensional DIRECT inversion method for microseismic locations and applicability tests over modeling data based on a downhole microseismic monitoring system. Synthetic tests inidcate that the objective function of locations can be defined as a multi‐dimensional matrix space by employing the global optimization DIRECT algorithm, because it can be run without the initial value and objective function derivation, and the discretely scattered objective points lead to an expeditious contraction of objective functions in each dimension. This study shows that the DIRECT algorithm can be extensively applied in real downhole microseismic monitoring data from hydraulic fracturing completions. Therefore, the methodology, based on a multidimensional DIRECT algorithm, can provide significant high accuracy and convergent efficiency as well as robust computation for interpretable spatiotemporal microseismic evolution, which is more suitable for real‐time processing of a large amount of downhole microseismic monitoring data. [ABSTRACT FROM AUTHOR]

Abstract Most unconventional oil and gas reservoirs contain some natural fractures, which play an essential role during reservoir reconstruction. Given the strong discontinuities in the displacement on both sides of the fracture as well as weak discontinuities in the pore fluid pressure, a novel three-dimensional seepage-stress coupling model using extended finite element method is proposed for fractured reservoirs. This directly coupled scheme for displacement field and stress field avoids the cumbersome process during calculating the fluid pressure in complicated fracture networks and translating into equivalent nodal force. Numerical examples are presented to simulate the fracture propagation pathway during the laboratory experiment on the staged synchronous fracturing of a horizontal well, revealing the deformation response and interaction mechanism between hydraulic fractures and natural fractures at orthotropic and non-orthotropic angles. The results show that due to the stress shadow effects, a non-planar fracture deflecting to wellbore would be formed during the progress of staged synchronous fracturing for a horizontal well. Moreover, the adjacent section to the intersection is opened and the others are closed for orthogonal natural fracture. In contrast, the non-orthogonal natural fracture is activated near the intersection at first and then fully opens as time increases; eventually, it is in the tensile-shear and composite state. In other words, the hydraulic fracture tends to traverse the orthogonal natural fracture and continue to propagate, as it is more easily arrested by the oblique natural fracture and transferred to propagation. Highlights • A novel hydro-mechanical coupling model is proposed for fractured porous media. • Numerical examples are presented to simulate the hydraulic fracture propagation paths. • We found that the induced hydraulic fracture tends to cross orthotropic natural fracture. • The induced hydraulic is prior to being arrested by the non-orthotropic natural fracture. [ABSTRACT FROM AUTHOR]

Abstract Effective development of shale oil/gas reservoirs depends on the success of hydraulic fracturing. Mineralogy and morphology play a very important role in establishing brittleness and therefore controlling its hydraulic fracturing characteristics. In this paper, mineralogical and morphological characteristics of the Older Cambay Shale and the top Olpad Formation from the northern Cambay Basin, India have been characterized using well logs, X-ray diffraction (XRD), field emission scanning electron microscopy (FESEM) coupled with energy dispersive X-ray spectroscopy (EDS or EDX) and atomic force microscopy (AFM) with the objective of identifying the fracturing potential of the units. Presence of mixed argillaceous mudstone, silica-rich argillaceous mudstone to argillaceous siliceous mudstone in the studied shale samples shows that the area under investigation is compositionally similar to the high clay facies of Marcellus and Barnett shale systems having low fracability. The studied formation is rich in kaolinite and chlorite, which aggregately contribute half of mineral composition ranging from 43 to 56%. Quartz, feldspar and mica combined to add approximately 30–43%, while siderite and magnesite varied between 8 and 12%. The interpreted results of mineralogical brittleness are supported by log based geomechanical properties. FESEM images at micro to nanoscale confirm the presence of various minerals with distinct crystal structure, along with inter-and-intra particle pores in the matrix. AFM scan at the nano scale shows mesopores ranging from 12 to 19 nm, with an average pore diameter of 17.57 nm and areal coverage of 10.9%. The log derived mechanical properties correlate with the mineralogy-based brittleness index (BI) of the studied shales indicating that the formations lie in the low to medium range of fracability. High clay content and low to moderate BI are likely to complicate the fracturing process of the potential resource rich area. Outcome of the present investigation demonstrates the limited shale oil/gas potential in the study area; however an extensive exploration program may unlock some sweet spots in the basin with distinctly different characteristics. Graphical abstract Image 1 Highlights • Fracture ability of the shale formations from of the part Cambay Basin was investigated from its mineralogy and morphology. • Studied shale is found to be rich in clay as per lithological classification. • Pore mapping specifies the presence of mostly mesopores with an average pore diameter of 17.58 nm. • Low to medium range of fracability indicates towards difficult fracturing of the shale oil/gas potential in the study area. [ABSTRACT FROM AUTHOR]

Summary: The heterogeneity of tight reservoirs significantly influences hydrofracturing behaviours, such as crack morphology, type, initiation, propagation, and distribution. The accurate characterisation of the influencing mechanisms has become a pivotal issue in enhancing the fracturing stimulation of tight reservoirs, as well as in the prediction of tight oil and gas production. In this study, the hydrofracturing behaviours of heterogeneous glutenites and their influencing mechanisms were numerically investigated based on bonded particle models (BPMs). The geometry and mechanical properties of the natural glutenites were obtained using microfocus computed tomography (CT) and triaxial tests and were used to construct heterogeneous BPMs. The hydrofracturing behaviours of the heterogeneous BPMs under various in‐situ stresses were analysed with hydro‐mechanical coupling effects considered and compared with those of homogeneous BPMs under the same conditions. The numerical results show that gravels in heterogeneous glutenites inhibit crack propagation. The shear cracks that appear in the initial stage of crack development subsequently propagate and distribute around the injection hole, and there are fewer hydraulic shear cracks than tensile cracks. The crack morphologies of BPMs are found to be consistent with the experimental forms. The numerical simulation provides a way to understand the mechanisms that govern the hydrofracturing crack types and propagation of heterogeneous reservoirs. [ABSTRACT FROM AUTHOR]

Oil production from unconventional tight Bakken reservoirs in North America has been booming since the early 2000s because of the widespread application of horizontal well drilling and multi-stage hydraulic fracturing technologies. Tight oil recovery is made difficult by the extremely low permeability and porosity of the oil-hosting rocks. Two key characteristics in tight oil production are the steep decline in oil production rate and the low ultimate oil recovery. Therefore, maintaining oil production and improving a field project’s economic benefits become urgent issues for the development of tight oil resources. The substantial amounts of residual oil left behind in tight reservoirs demand a viable and effective enhanced oil recovery (EOR) technology after the primary recovery process. This research investigated the effectiveness of miscible or immiscible gas flooding processes using four possible injection gas candidates (i.e., CO 2 , CO 2 -enriched flue gas, oilfield-produced gas, and nitrogen) for Bakken tight oil reservoirs in southeast Saskatchewan, Canada. The phase behaviour of the reconstituted live oil–injection gas systems was studied through pressure/volume/temperature (PVT) tests in which important recovery mechanisms of gas flooding, i.e., viscosity reduction and oil swelling effects, were revealed. The minimum miscibility pressures (MMP) for the live oil–injected gas systems were determined using the rising bubble method. The experimental results demonstrated that CO 2 had the lowest MMP and largest viscosity reduction and oil swelling among all the tested gases. Therefore, CO 2 flooding is considered technically feasible as a miscible process at the current reservoir conditions, while the use of the other three gases would result in an immiscible process. Finally, four coreflood tests using reservoir cores from the Viewfield Bakken field were conducted to evaluate the displacement efficiency. Each coreflood comprised four stages (pressure depletion, initial waterflood, gas injection, and extended waterflood) to represent the actual field production practice. Oil recovery performance confirmed that CO 2 miscible flooding was significantly more effective than immiscible flooding with the other injection gases. [ABSTRACT FROM AUTHOR]

A self-diverting fracturing technology is proposed in the study as a way of effectively creating a stimulated reservoir volume. The technology, which is based on the use of a novel self-diverting fracturing fluid, can create and extend fractures to design shapes, is strong enough to effectively plug fractures and can then be effectively removed from fractures and form a branched network of highly permeable fractures. It can also greatly enlarge the stimulated reservoir volume, possesses excellent injecting and plugging capacity, effective diversion and complete self-plugging ability, produces little reservoir damage, and is simple and practical. Gelling and gel-breaking macrophenomena, temporary plugging, diversion, and fluid loss are described in detail. All the test results demonstrate that the present self-diverting fluid fracturing technology possesses many advantages. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing is an important method of reservoir stimulation in the exploitation of geothermal resources, and conventional and unconventional oil and gas resources. In this article, hydraulic fracturing experiments with shale, sandstone cores (from southern Sichuan Basin), and granite cores (from Inner Mongolia) were conducted to investigate the different hydraulic fracture extension patterns in these three reservoir rocks. The different reactions between reservoir lithology and pump pressure can be reflected by the pump pressure monitoring curves of hydraulic fracture experiments. An X-ray computer tomography (CT) scanner was employed to obtain the spatial distribution of hydraulic fractures in fractured shale, sandstone, and granite cores. From the microscopic and macroscopic observation of hydraulic fractures, different extension patterns of the hydraulic fracture can be analyzed. In fractured sandstone, symmetrical hydraulic fracture morphology could be formed, while some micro cracks were also induced near the injection hole. Although the macroscopic cracks in fractured granite cores are barely observed by naked eye, the results of X-ray CT scanning obviously show the morphology of hydraulic fractures. It is indicated that the typical bedding planes well developed in shale formation play an important role in the propagation of hydraulic fractures in shale cores. The results also demonstrated that heterogeneity influenced the pathway of the hydraulic fracture in granite cores. [ABSTRACT FROM AUTHOR]

Hydrofracturing is a remarkable technology for unconventional oil and gas exploitation in tight reservoirs, in which the fluid-driven propagation of hydraulic fractures in a porous medium rock reservoir is an extremely complex physical process, for which there are great challenges in numerical simulation, such as multiphysical field coupling, multiple field evolution on engineering-scale reservoirs, and multi-scale fracture propagation processes. This complex physical process renders it difficult to obtain reliable solutions rapidly and efficiently. Understanding the behavior and mechanism of hydrofracturing is complicated. A multi-thread parallel computation scheme for solid and fluid analysis was developed to improve computational efficiency in large-scale models and multi-physical field coupling (hydro-mechanical) problems, and fracture criteria via a dual bilinear cohesive zone model was introduced. Considering the hydro-mechanical coupling and leak-off effects, the combined finite element-discrete element-finite volume approach was introduced and implemented successfully, and a multi-thread parallel computation method and global procedure was proposed. This study provides valuable results for parallel computation of dynamic fluid-driven propagation of hydraulic fractures in porous elastic rock mass and lays the foundation for further development of efficient and reliable simulations for dynamic multiscale complex fractures under multiphysical field coupling. [ABSTRACT FROM AUTHOR]

We use stochastic modeling, the permeability tensor principle, and the finite-element method to construct a discrete complex model of a fracture network, an equivalent continuum model, and a continuum model for anisotropic seepage in a complex fracture network described using the permeability tensor. Solution of these models lets us describe the process of gas production from reservoirs after hydraulic fracturing. In these models, we fully take into account the geological structural features of hydraulically fractured tight reservoirs and the morphology of three-dimensional fracture networks. We obtain a new model for predicting production from tight gas reservoirs after hydraulic fracturing. [ABSTRACT FROM AUTHOR]

When an owner's activities within an oil and gas reservoir physically invade the portion of the reservoir owned by its neighbors, the immediate response is "trespass." The trespass response is based upon the extension of surface property lines to define rights to subsurface geologic structures. The basic flaw with this analysis is that the oil and gas reservoir is an interconnected geologic system that cannot be divided into segregated parts. Instead, each owner has collective as well as individual rights in the reservoir. This article identifies the collective rights of reservoir owners and the reservoir community analysis used to distinguish appropriate from inappropriate use of the reservoir. These rights, and the reservoir community analysis, will be illustrated by applying them to cross-boundary intra-reservoir issues associated with hydraulic fracturing. The first are frac fissures that invade neighboring portions of the reservoir. The second are frac pressures that invade neighboring portions of the reservoir and sometimes disrupt existing production operations. [ABSTRACT FROM AUTHOR]

Using the model information and in situ data on hydrofracturing in an oil and gas reservoir of the Bakken Formation (USA), potential of locating hypocenters of microseismic events concurrently with determining parameters of velocity anisotropy of seismic waves in rock mass is analyzed. It is shown that inclusion of anisotropy in the analysis improves accuracy of spatial location of microseismic event hypocenters and increases validity of estimation of the fracturing direction. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing is regarded as one of the essential techniques for developing shale reservoirs at present. During fracturing, propagation of multi-fractures and complex fracture network is developed as result of interactions between preexisting natural fractures and hydraulic fractures, as evidenced by microseismic event patterns. This paper introduces a new mathematic model for analyzing the growth and geometry of fracture network in association with criterions of dilation and propagation based on the theory of fracture mechanics. The solution method concentrates on both extension description and dimensions calculation of every branching fracture through local explicit computation and iteration improvement. Simulation results indicate that the complex fracture network significantly depends on the features of preexisting natural fractures, optimization of fracturing parameters and materials for realizing simultaneous extension at higher net pressure. The areas with less horizontal stress contrast would increase curvature radius of fracture propagation path, which facilitates interconnection with more natural fractures on the lateral plane, and also expands network volume. Propagating angle and pressure at fracture tip for further propagation and dimensions computation are influenced by the properties of natural fractures, such as length and orientation. By using actual treatment parameters, complex fracture model is corrected against microseismic monitoring patterns by matching the distribution and density of interpretation data with geometry and complexity of simulation results; it is also applicable to fracturing design. [ABSTRACT FROM AUTHOR]

Water-soluble polymers as drag reducers have been widely utilized in slick-water for fracturing shale oil and gas reservoirs. However, the low viscosity characteristics, high operating costs, and freshwater consumption of conventional friction reducers limit their practical use in deeper oil and gas reservoirs. Therefore, a high viscosity water-soluble friction reducer (HVFR), poly-(acrylamide-co-acrylic acid-co-2-acrylamido-2-methylpropanesulphonic acid), was synthesized via free radical polymerization in aqueous solution. The molecular weight, solubility, rheological behavior, and drag reduction performance of HVFR were thoroughly investigated. The results showed that the viscosity-average molecular weight of HVFR is 23.2 × 106 g⋅mol−1. The HVFR powder could be quickly dissolved in water within 240 s under 700 rpm. The storage modulus (G′) and loss modulus (G″) as well as viscosity of the solutions increased with an increase in polymer concentration. At a concentration of 1700 mg⋅L−1, HVFR solution shows 67% viscosity retention rate after heating from 30 to 90 °C, and the viscosity retention rate of HVFR solution when increasing CNaCl to 21,000 mg⋅L−1 is 66%. HVFR exhibits significant drag reduction performance for both low viscosity and high viscosity. A maximum drag reduction of 80.2% is attained from HVFR at 400 mg⋅L−1 with 5.0 mPa⋅s, and drag reduction of HVFR is 75.1% at 1700 mg⋅L−1 with 30.2 mPa⋅s. These findings not only indicate the prospective use of HVFR in slick-water hydrofracking, but also shed light on the design of novel friction reducers utilized in the oil and gas industry. [ABSTRACT FROM AUTHOR]

• Autoencoder neural network is developed for 3D parameter dimension reduction. • Neural network releases prior Gaussian assumption and shortens the burn-in period. • Method allows heterogeneous permeability estimation even from single well test. Determining permeability distributions in reservoirs is critical for the management of limited earth resources. While hydraulic fracturing is widely used to enhance the permeability of deep geothermal, gas and oil reservoirs, it remains challenging to infer heterogeneous distributions of permeability. Typically, a limited number of boreholes are available at which reservoir imaging and tracer testing can be conducted. The number of observations is often far fewer than the number of estimable permeability parameters, making model inversion ill-posed. To overcome this problem, the autoencoder neural network was combined with a Bayesian inversion algorithm based on Markov Chain Monte Carlo (MCMC) sampling, in order to estimate the spatial distributions of permeability in an enhanced geothermal reservoir, conditional to temperature and outflow rate observations from a single-well-injection-withdrawal test (SWIW). The autoencoder neural network was used to reduce parameter dimensionality by four orders of magnitude. MCMC sampling was used to estimate low-dimensional parameters via inversion of SWIW observations. A high-resolution permeability distribution was reconstructed from the low-dimensional parameterization through reapplication of the autoencoder neural network. Application to a synthetic enhanced geothermal system demonstrated that the methodology achieved rapid stabilization and low permeability estimation error (<10%). By combining deep-learning method with Bayesian inversion, permeability distributions in geo-energy reservoirs can be estimated from a limited set of borehole data. [ABSTRACT FROM AUTHOR]

Fracture propagation coupled with fluid flow in porous media has very important applications in fracking in oil and gas reservoirs, corrosion in ceramics, and degradation of human bones. Modeling fracture failure in porous media governed by the coupled solid and fluid field equations is challenging and time-consuming. This paper extends discontinuous Galerkin (DG) finite element methods to model crack openings in porous media through exploiting an easy construction of interfaces for potential crack paths by locally breaking continuous elements. Consequently, a finite element mesh for fracture apertures is completely and gracefully constructed using DG interface objects as well as the definitions of jumps of displacements across the DG interfaces defined for bulk matrices. Furthermore, rigid cohesive laws often adopted for crack openings can be naturally implemented in DG formulations without introducing artificial stiffness, which may eventually improve the performance for implicit formulations in handling crack openings in porous media. In this work, we perform a consistent, fully implicit, and fully coupled hybrid DG/continuous finite element formulation for three field equations including the solid, bulk fluid, and fluid in fracture apertures resulting from crack openings. We verify our DG formulation and implementation using the Khristianovich-Geertsma-DeKlerk analytical solutions. Finally, we further demonstrate a good performance of the proposed DG method by modeling fracking in an oil reservoir containing two nature fractures. • A fully implicit and fully coupled hybrid IIPG/CG formulations. • Easy incorporatation of rigid cohesive laws in DG methods. • Verification of DG formulation using KGD benchmark. • A two-fracture propagation in porous media simulated. [ABSTRACT FROM AUTHOR]

Exploring engineering methods for increasing fracture network complexity is important for the development of unconventional oil and gas reservoirs. In this study, we conducted a series of fracturing experiments on naturally fractured volcanic samples. An injection method, multiple flow pulses, is proposed to increase fracture complexity. The results show that fluid leaked into the natural fracture network (NFN) when the injection rate was low (0.2 mL/min); hydraulic-fracture-dominant fracture geometry was created with an injection rate of 2 and 5 mL/min. Under the 2 mL/min-injection scheme with 3 pulses, the injection pressure during the intermittent stage was low (<5 MPa), resulting in a limited increase in fracture complexity. When the number of the flow pulses increased to 5, the pressure drop rate in the fourth and fifth intermittent stage significantly increased, indicating an increase in the aperture of natural fractures (NFs) and in the fluid leak-off effect. Under the 5 mL/min injection scheme containing 5 pulses, besides the enhanced fluid leak-off, a sharp injection pressure drop was observed, indicating the activation of NFs. The complexity and the aperture of the ultimate fracture network further increased. The injection method, multiple flow pulses, can be used to create complex fracture networks effectively. [ABSTRACT FROM AUTHOR]

Anisotropy is an important property of inhomogeneous underground rocks and a central topic for geophysical exploration. Detecting the inhomogeneous anisotropy of rocks is key for rational oil and gas reservoir utilization and well placement optimization. Conventional cross dipole measurements can only evaluate the anisotropy of formation rocks near the borehole wall, and are therefore unable to evaluate the rock anisotropy at a distance from the borehole. This study investigates the anisotropic distribution of rock heterogeneity and the resulting azimuthal variation of the acoustic scattering intensity. The results show that this azimuthal scattering intensity variation of the dipole shear-wave acoustic logging data can be used to evaluate the anisotropic distribution of the rock heterogeneity. A borehole model with a three-dimensional heterogeneous and anisotropic elastic formation was established first, and the dipole acoustic logging along the borehole model was simulated using a finite difference technique. The wave-scattering effect in the borehole dipole wave data, measured in terms of a coda wave attenuation, was analyzed. The scattering attenuations of coda waves measured in different azimuthal directions exhibit significant variations, which are related to the azimuthal variation of the formation inhomogeneity. Based on the results of theoretical modeling, a method for the evaluation of the anisotropic variation of formation inhomogeneity (via azimuthal pattern of the scattering attenuations) was proposed. The method was applied to dipole acoustic logging data, acquired before and after hydraulically fracturing a tight reservoir. The field data results show that the scattered dipole-shear coda wave attenuation of the after-fracturing data exhibits an elongated, anisotropic variation pattern, where the direction of elongation coincides with the fracture extension direction. This indicates good potential for using the proposed method for hydraulic fracture evaluation. Because wave scattering occurs in a large volume around the borehole, application of this method and analysis can significantly enhance the measurement volume of the cross-dipole logging technology. This extends its effectiveness toward the evaluation of hydraulic fracturing results for unconventional reservoirs (e.g., shale gas). • 3D borehole heterogeneous anisotropy model was building. • Scattering field was calculating by time-domain finite difference technique. • Scattering attenuation was calculating by energy flux model. • Borehole elastic wave anisotropic scattering was used to evaluating hydraulic fracturing for unconventional reservoirs. [ABSTRACT FROM AUTHOR]

Multistage hydraulic fracturing is a highly effective method for creating multiple transverse fractures to improve gas and oil reservoir production. It is critical to minimize the fracture spacing while also ensuring transverse propagation of fractures in multi-fractured horizontal wells. In this paper, a 3D fully coupled pore pressure-stress model based on the extended finite element method (XFEM) combined with the cohesive zone method is established to simulate five different fracturing scenarios in close spacing. The sensitivity of mesh size and the integration method are optimal, which are verified by the highly accurate traditional cohesive zone method. Then, the effect of five different fracturing scenarios on fracture geometries is compared. It is shown that spacing is a key parameter controlling fracture geometries in all fracturing scenarios. Alternative sequential and modified two-step fracturing can significantly reduce the influence of stress shadowing to generate more transverse fractures and form longer effective fractures. The sequential and two-step fracturing see an obvious improvement with increased fracture effective length when the spacing increases. The simultaneous fracturing technique can result in excessive closure of the middle fractures, which causes serious insertion of proppants. These results offer a new insight on optimization of hydraulic fracturing and can be a guidance for typical field cases. [ABSTRACT FROM AUTHOR]

There are multiporosity media in tight oil reservoirs after stimulated reservoir volume (SRV) fracturing. Moreover, multiscale flowing states exist throughout the development process. The fluid flowing characteristic is different from that of conventional reservoirs. In terms of those attributes of tight oil reservoirs, considering the flowing feature of the dual-porosity property and the fracture network system based on the discrete-fracture model (DFM), a mathematical flow model of an SRV-fractured horizontal well with multiporosity and multipermeability media was established. The numerical solution was solved by the finite element method and verified by a comparison with the analytical solution and field data. The differences of flow regimes between triple-porosity, dual-permeability (TPDP) and triple-porosity, triple-permeability (TPTP) models were identified. Moreover, the productivity contribution degree of multimedium was analyzed. The results showed that for the multiporosity flowing states, the well bottomhole pressure drop became slower, the linear flow no longer arose, and the pressure wave arrived quickly at the closed reservoir boundary. The contribution ratio of the matrix system, natural fracture system, and network fracture system during SRV-fractured horizontal well production were 7.85%, 43.67%, and 48.48%, respectively in the first year, 14.60%, 49.23%, and 36.17%, respectively in the fifth year, and 20.49%, 46.79%, and 32.72%, respectively in the 10th year. This study provides a theoretical contribution to a better understanding of multiscale flow mechanisms in unconventional reservoirs. [ABSTRACT FROM AUTHOR]