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Mechanical heterogeneity is a major characteristic of the organic-rich shale. The relation between mechanical heterogeneity and formation in-situ stress has been seldomly addressed but important to understand hydraulic fracture propagation, wellbore stability, and hydrocarbon flow. In this paper, the grid nanoindentation technique was used to characterize the heterogeneity of the mechanical properties of Longmaxi organic-rich shales from various burial depths and in-situ stress. The measured elastic modulus and hardness of each sample are deconvolved into three phases including soft phase, medium stiff phase and stiff phase according to mineral category. As the burial depth and corresponding in-situ stress increase, the overall elastic modulus and hardness of the sample enhance. Simultaneously, the percentage of soft minerals decreases, and the probability distribution tends to concentrate through 95% confidence interval evaluation which demonstrates weakened heterogeneity. Furthermore, SEM images provide evidence that extended cracking, initiated cracking, crushing and ductile deforming always occur around indentation imprints. This confirms that even under deep buried depth and high in-situ stress, brittle fracture and ductile deformation can exist synchronously. This paper demonstrates the influence of in-situ stress on the heterogeneity of shale micromechanics.

Proppant is a key material for enhancing unconventional oil and gas production which requires a long distance of migration and efficient liquid conductivity paths within the hydraulic fracture. However, it is difficult to find a proppant with both high self-suspension ability and liquid conductivity. Here, a simple method is developed to coat epoxy resin onto the ceramic proppant and fabricate a novel coated proppant with high hydrophobicity, self-suspension, and liquid conductivity performance. Compared with uncoated ceramic proppants, the epoxy resin coated (ERC) proppant has a high self-suspension ability nearly 16 times that of the uncoated proppants. Besides, the hydrophobic property and the liquid conductivity of the ERC proppant increased by 83.8% and 16.71%, respectively, compared with the uncoated proppants. In summary, this novel ERC proppant provides new insights into the design of functional proppants, which are expected to be applied to oil and gas production.

Pore structure characterization and its effect on methane adsorption on shale kerogen are crucial to understanding the fundamental mechanisms of gas storage, transport, and reserves evaluation. In this study, we use 3D scanning confocal microscopy, scanning electron microscopy (SEM), X-ray nano-computed tomography (nano-CT), and low-pressure N2 adsorption analysis to analyze the pore structures of the shale. Additionally, the adsorption behavior of methane on shales with different pore structures is investigated by molecular simulations. The results show that the SEM image of the shale sample obviously displays four different pore shapes, including slit pore, square pore, triangle pore, and circle pore. The average coordination number is 4.21 and the distribution of coordination numbers demonstrates that pores in the shale have high connectivity. Compared with the adsorption capacity of methane on triangle pores, the adsorption capacity on slit pore, square pore, and circle pore are reduced by 9.86%, 8.55%, and 6.12%, respectively. With increasing pressure, these acute wedges fill in a manner different from the right or obtuse angles in the other pores. This study offers a quantitative understanding of the effect of pore structure on methane adsorption in the shale and provides better insight into the evaluation of gas storage in geologic shale reservoirs.

Summary Knowing the location of sweet spots benefits the horizontal well drilling and the selection of perforation clusters. Generally, geoscientists determine sweet spots from the well-logging interpretation. In this paper, a group of prevalent classifiers [extreme gradient boosting (XGBoost), unbiased boosting with categorical features (CatBoost), and light gradient boosting machine (LightGBM)] based on gradient-boosting decision trees (GBDTs) are introduced to automatically determine sweet spots based on well-log data sets. Compared with linear support vector machines (SVMs), these robust algorithms can deal with comparative scales of features and learn nonlinear decision boundaries. Moreover, they are less influenced by the presence of outliers. Another prevailing approach, named generative adversarial networks (GANs), is implemented to augment the training data set by using a small number of training samples. An extensive application has been built for the field cases in a certain oilfield. We randomly select 73 horizontal wells for training, and 13 features are chosen from well-log data sets. Compared with conventional SVMs, the agreement rates of interpretation by XGBoost and CatBoost are significantly improved. Without special preprocessing of the input data sets and conditional tabular GAN (CTGAN) model fine tuning, the fake data set could still bring a relatively low agreement rate for all detections. Finally, we propose an ensemble-learning framework concatenating multilevels of classifiers and improve agreement rate. In this paper, we illustrate a new tool for categorizing the reservoir quality by using GBDTs and ensemble models, which further helps search and identify sweet spots automatically. This tool enables us to integrate experts’ knowledge to the developed model, identify logging curves more efficiently, and cover more sweet spots during the drilling and completion treatment, which immensely decrease the cost of log interpretation.

Abrasive waterjet (AWJ) fracturing has become an accepted horizontal multistage stimulation technique due to its flexibility and high efficiency of extensive fracture placement. The downhole tool failure of AWJ fracturing becomes an issue in the massive hydraulic fracturing because of high velocity and proppant erosion. This paper proposed a 3D computational fluid dynamics (CFD)-based erosion model by considering high-velocity waterjet impact, proppant shear erosion, and specific inner structure of hydra-jet tool body. The discrete phase approach was used to track the proppant transport and its concentration distribution. Field observation provides strong evidence of erosion patterns and mechanisms obtained from CFD simulation. The results show that the erosion rate has a space dependence in the inner wall of the tool body. The severe erosion areas are primarily located at the entries of the nozzle. Evident erosion patterns are found including a ‘Rabbit’s ear’ erosion at the upper-layer nozzles and a half bottom loop erosion at the lower-layer nozzles. Erosion mechanisms attribute to high flow velocity at the entry of nozzles and the inertia force of proppant. Sensitivity analysis demonstrates that the pumping rate is a primary factor contributing to erosion intensity.

Properties of shale in an acid environment are important when acid or CO2 is injected into geologic formations as a working fluid for enhanced oil and gas recovery, hydraulic fracturing and reduced fracture initiation pressure. It has previously been shown that acid fluids can enhance the formation conductivity and decrease the hardness of shale. However, less is known about the effect of dilute acid on the adhesion properties of shale. In the study, shale samples are characterized in detail with advanced analysis. Adhesion properties of shale via dilute acid treatment were revealed by atomic force microscopy (AFM) for the first time. Results indicate that acid treatment can greatly enhance adhesion forces of the shale surface. After acid treatment, the average adhesion forces show a platform-like growth with an increase in loading force. Through analysis of results from AFM, scanning electron microscopy, and X-ray diffraction, we affirm that the enhanced adhesion forces are mainly from increased specific surface area and reduced elastic modulus. The results presented in this work help understand the adhesion properties of shale oil/gas present in an acidic environment, which have great significance in unconventional resources development.

It is a common phenomenon during CBM drilling and production that reservoir damage is not eliminated completely. In view of this, a technical idea of composite pulsating hydraulic fracturing of radial horizontal wells which is conducive to blockage removing and stimulation was put forward in this paper. Speaking of the hydraulic jetting in a multi-branch radial well, it is to conduct pulsating hydraulic fracturing moderately through a high-diversion radial hole, so as to crush and break coal beds near the main hole to the uttermost. Thus, an extensive pressure relief and permeability increase area where high-diversion pathways are combined with fracture networks is formed. Then, to verify its technical principles, laboratory tests on pulsating hydraulic fracturing of radial wells were designed and carried out. Besides, the relationships of the features of acoustic emission (AE) response during the formation of fractures by composite fracturing of radial horizontal wells vs. coal breaking degree and macro fracture morphology were experimentally studied by using a pulse servo fatigue testing machine and an acoustic emission detector. And the following research results were obtained. First, under experimental conditions, fractures initially occur when the pressure of composite pulsating hydraulic fracturing of radial horizontal wells is 1/3–1/4 of the peak pressure of conventional fracturing, and the amount of its AE events is 1.38–7.07 times that of conventional fracturing. Second, when composite pulsating hydraulic fracturing of radial horizontal wells is conducted, AE emission signals respond strongly, the peak pressure for macro fracturing is lower and a larger fracture network can be generated more easily under the same condition. Third, radial laterals amount, borehole length, dynamic loading frequency and amplitude are the important factors affecting the effect of composite pulsating hydraulic fracturing of radial horizontal wells. In conclusion, composite pulsating hydraulic fracturing of radial horizontal wells provides a new idea of removing the blockages in CBM reservoirs and developing CBM efficiently, realizing effective blockage removing and stimulation of CBM wells. Keywords: Coalbed methane, Reservoir damage, Stimulation, Radial horizontal well, Composite pulsating hydraulic fracturing, Blockage removing, Laboratory

Acoustic emission has been recognized as a potentially advanced technique to monitor the efficiency of high-velocity waterjet rock drilling. Identification of AE multi-sources signals becomes fundamental to correlate AE singles and rock drilling efficiency. This paper presents a controlled experimental scheme and frequency analysis to identify different signal sources from waterjet impact and rock failure, respectively. Acoustic signals were decomposed into low, medium, and high-frequency signals by using the variational mode decomposition (VMD) approach. Results indicate that the waterjet impact generates a wideband acoustic signal. The frequency distribution of the high-frequency signals exhibited a strong diversity among four materials because of their different acoustic attenuation. Furthermore, the waterjet pressure did not change the frequency domain distribution of the material. An obvious reduction of the high-frequency signals was observed while waterjet rock drilling. Furthermore, the main frequency of high-frequency signals starts to be time-dependent that causes from the rock failure process. The high-frequency band presented a good correlation with the rate of penetration.

Fluid imbibition is a recognized strong phenomenon in tight shale that could greatly influences the dynamic failure behaviors. An experimental study was carried out to account for the influences of three typical drilling fluids (Air, Oil-based, and Water-based) on dynamic mechanics of tight shale. The collected samples were separated into three groups by the treatment of the distilled water saturation, white oil saturation, and drying, respectively. The dynamic properties involving Young's modulus, Compression strength, and specific energy consuming were experimentally measured by using Split Hopkinson Pressure Bar (SHPB). Results confirm that the fluid imbibition phenomena perform a promising influence on dynamic rock mechanics of tight shale. There are very different responses induced by air dry, oil, and water imbibition on dynamic rock strength, cutting size, and energy consuming. Oil imbibition is capable to enhance the strength, achieve uniform size of cutting, and consume less specific energy to break unit volume of rock. Comparatively, water imbibition sharply reduces the strength and consumes much less specific energy. Air dry condition makes much bigger and non-uniform cuttings and consumes the most specific energy. Those observations are no longer the same with obtained knowledge from sandstone and concrete, which attribute to the nanoscale pore distribution and fluid sensitivity of tight shale.

Radial borehole fracturing is a technology combing hydraulic fracturing and slender boreholes which are radially drilled from the main wellbore by water jets. This paper aims to investigate how the radial boreholes influence the fracture extension when they are pressurized by the fracturing fluids. Concrete blocks containing radial boreholes were cast, the mechanical properties of such blocks were tested, and these samples were hydraulically fractured through a laboratory tri-axial fracturing apparatus. Experimental results show that increasing the azimuths of the radial boreholes enhances the breakdown pressures, but it will reduce the fracture extension distances (deviation distances) paralleling to the radial borehole axes. Similar trends appear when the horizontal stress differences diminish and the distances between adjacent layers of radial borehole axes increase. When changing the numbers of the radial boreholes, the variations of the breakdown pressures depend on the layouts of the radial boreholes. Besides, increasing the pump rates lifts the breakdown pressures and enhances the deviation distances. Compared to perforation fracturing, radial borehole fracturing has higher breakdown pressures and stronger control to fracture propagation. It is concluded that the extrusion forces exist in the horizontal zones between the radial boreholes. A conceptual model is proposed which can explain the variations of the deviation distances. When the injection time of the fracturing fluids is identical, the higher breakdown pressures will decrease the deviation distances because of the extrusion forces. There is a balance between the lower breakdown pressures and the higher pore pressures both caused by the more penetration of the fracturing fluid, which can either increase the deviation distances or reduce the deviation distances.

A production forecasting model for shale gas reservoirs is proposed based on the continuum medium theory (organic/inorganic matrix) and discrete fracture model (fracture system). The fractal property of the pore size distribution of shale matrix is considered. The stability and accuracy of the model are successfully validated with the field data. Variations of different flow mechanisms during the exploitation of shale gas are investigated. The sensitivities of gas production to the pore size distribution of shale matrix, natural fracture parameters and hydraulic fracture parameters are analyzed. Our results show that: (1) The contribution of the convective flow and surface diffusion to total gas flow increases with the depletion of shale gas, while that of the bulk diffusion and Knudsen diffusion decreases gradually. (2) Among the fractal pore-size parameters, the maximum inorganic pore diameter has the most significant impact on the cumulative gas production of up to 13.9%. (3) After the natural fracture number increases to a certain extent, gas production increases slowly even if more natural fractures exist in the reservoir. The complex fracture network is beneficial to increase shale gas production. (4) The cumulative gas production rises as the increase of the hydraulic fracture half-length, flow conductivity, spacing and number. The rapid production rate in the early production stage may result in a fast reservoir energy depletion, which has a negative effect on production.

Based on bubble dynamics theory, a mathematic model describing the cavitation bubble size variation in the flow field of self-resonating cavitating jet was developed considering the pressure field and mass and heat exchange between cavitation bubble and ambient fluid. With this model, the influence factors on the cavitation intensity are investigated. The results show that the destructiveness of cavitating jet in breaking rocks depends on the bubble's first collapse, with decreasing intensity in the subsequent collapses. The self-resonating effect significantly enhances the cavitation intensity by promoting the collapse pressure and elongating its duration. Hydraulic parameters are proven to be the dominating factors influencing cavitation intensity: while collapse intensity monotonously increases with jet velocity, there exists an optimum ambient pressure where highest collapse intensity can be achieved. Conversely, the fluid properties show minor influences: cavitation intensity only slightly decreases with the increasing of fluid's density and barely changes with the variation of viscosity and surface tension. The results from this investigation help to uncover the mechanism of the enhanced erosion potential of self-resonating cavitating jet. The conclusions can be used to further improve the performance of self-resonating cavitating jet in field applications. Key words: self-resonating cavitating jet, cavitating bubble, collapse intensity, hydraulic parameters, fluid properties

The aim of the present study is to help understand hydraulic fracture propagation in shale formations through numerical simulations. The hydraulic fracture propagation regime in shale is analyzed considering the anisotropic nature of the shale rock formation and slick-water fracturing fluid. It is determined that the dominant mechanism of hydraulic fracture propagation is the so-called transitional regime that is characterized by a negligibly small fluid lag region and zero fluid front pressure. For the modeling of the hydraulic fracture evolution over time, we assume orthotropic linear-elastic rock media and that the flow of the fracturing fluid is governed by the Reynold's lubrication equation. For the discretization of the coupled solid-fluid equations within the 2D plane-strain context we use the extended finite element method for the rock media and the finite volume method for the lubrication equation. The problem of the hydraulic fracture evolution over time is modeled as stable quasi-static crack growth where time is the result of upholding the mass conservation principle between the fluid inflow and the crack volume. The Picard iterative approach is used to solve the discrete non-linearly coupled solid-fluid equations. Our model is verified against several analytical solutions. Subsequently, a five-stage hydraulic fracturing problem is simulated to study the interactions between the different fractures. Results show that the on-going hydraulic fractures are attracted by the pre-existing hydraulic fractures as a result of the change of the local stress field relative to the initial in-situ stress field. For the cases considered, fracture deflections are found to be most extensive with decreasing fracture spacing and in-situ stress difference, but insensitive with the increasing the ratio of Young's moduli.

The adsorption of carbon dioxide and methane binary mixture in shale kerogen nanopores and the underlying mechanism significantly affect the supercritical carbon dioxide enhanced shale gas development project. In this study, we investigated the adsorption properties of carbon dioxide and methane in shale kerogen using grand canonical Monte Carlo (GCMC) method. Shale kerogen was fabricated based on Ungerer molecular model and its parameters were validated. The effects of temperature, pressure, mole fraction on the adsorption isotherms, average isosteric heat, potential energy distribution, and adsorption selectivity of binary mixture were discussed. The results show that the absolute adsorption capacity of methane in binary mixture decreases as temperature increases, but increases as mole fraction increases. Compared with methane, carbon dioxide is in lower energy absorption sites, which indicates the adsorption capacity of carbon dioxide in shale kerogen is stronger than that of methane. The adsorption selectivity of carbon dioxide over methane first decreases as pressure increases until pressure reaches critical pressure (7.38 MPa for carbon dioxide), and then stays at around 3.8 as pressure continues to rise. Adsorption selectivity and desorption quantity are used to reveal that the optimal injection depth for supercritical carbon dioxide enhanced shale gas development project is 1000–2500 m. This study will reveal the mechanism of the adsorption of methane in kerogen and provide some fundamental data for supercritical carbon dioxide enhanced shale gas development project.

Summary Two-phase flow is generally significant in the hydraulic-fracturing design of a shale-gas reservoir, especially during the flowback period. Investigating the gas- and water-production data is important to evaluate stimulation effectiveness. We develop a semianalytical model for multifractured horizontal wells by incorporating the two-phase flow in both shale matrix and fracture domains. The complex-fracture network, including both primary/hydraulic fractures and secondary/natural fractures, is modeled explicitly as discretized segments. The node-analysis approach is used to discretize the networks into a number of fracture segments and connected nodes, depending on the complexity of the fracture system. The two-phase flow is incorporated by iteratively correcting the relative permeability to gas/water for each fracture segment and capillary pressure at each node with the fracture depletion. The accuracy of the proposed model is confirmed by the numerical model. Subsequently, the early-time gas- and water-production performance is analyzed by use of various fracture geometries and network configurations. The model was also used to history match an actual multistage hydraulically fractured horizontal well in the Marcellus Shale during the flowback period. The research findings have shed light on the factors that substantially influence the gas- and water-production behavior during the flowback period. We also investigate the effects of fracture-network geometries and complexities on the gas/water-ratio (GWR) diagnostic plots. The results depict that the GWR behavior on the diagnostic plots is highly dependent on fracture-network geometry, configuration, and connectivity, which could assist in deriving the critical fracture properties affecting the production performance. This work extends the semianalytical approach previously proposed for modeling single-phase to two-phase flowback problems in unconventional reservoirs with various fracture-network geometries. The method is easier to set up and is less data-intensive than use of a numerical reservoir simulator, and is capable of providing a straightforward and flexible way to model complex-nonplanar-fracture networks in a multiphase-flow environment.

The success of waterjet drilling technology requires further insight into the rock failure mechanisms under waterjet impingement. By combining acoustic emission (AE) sensing and underwater sound recording techniques, an online system for monitoring submerged waterjet drilling has been developed. For four types of sedimentary rocks, their AE characteristics and correlations to the drilling performance have been obtained through time–frequency spectrum analysis. The area under the power spectrum density curve has been used as the indicator of AE energy. The results show that AE signals from the fluid dynamics and the rock failure are in different ranges of signal frequency. The main frequencies of the rock failure are within the higher range of 100–200 kHz, while the frequencies of the fluid dynamics are below 50 kHz. Further, there is a linear relationship between the AE energy and the drilling depth irrespective of rock type. The slope of the linear relationship is proportional to the rock strength and debris size. Furthermore, the AE-specific energy is a good indicator of the critical depth drilled by the waterjet. In conclusion, the AE characteristics on the power density and dominant frequency are capable of identifying the waterjet drilling performance on the rock materials and are correlated with the rock properties, i.e., rock strength and cutting size.

The utilization of acid has been approved as a potential approach to enhance Stimulated Reservoir Volume (SRV) by creating secondary pores and microfractures in shale reservoirs. This paper proposed an acid soaking technique to quantify the generation of microfracturing behaviors. Two types of core samples from distinct shale depositional environments, namely Longmaxi carbonate-rich, and Yanchang clay-rich shale were emphasized. Hydrochloric acid (15%+ 3%KCL) was utilized to treat the shale samples for a period of 2 hours. Scanning Electron Microscope (SEM) and X-ray diffraction (XRD) experiments were performed to correlate the individual mineral phases. Inductively coupled plasma-optical emission spectrometry (ICP-OES) and X-ray fluorescence tests (XRF) were utilized, to quantify the elemental analysis of the distinct mineral phases. For post acidizing test conditions, three different types of microfractures, namely stress-induced micro-fractures, acid dissolution micro-fractures, and acid shrinkage micro-fractures were observed. For the clay-rich shale, the stress-induced microfractures were more prominent within the Kaolinite and the boundary edges of the Chlorite/Biotite regions. Whereas, shrinkage micro-fractures dominated the chlorite regions. The Longmaxi carbonate-rich shale, on the other hand, revealed more evidence of the creation of acid dissolution microfractures within Anhydrite, calcite, illite, and organic matter regions. According to the ICP-OES and XRF test results, the clay-rich shale sample underwent excessive ionic imbibition, as well as an ion dislodgment mechanism. However, the carbonate-rich shale experienced only the ion dislodgment mechanism from the shale interface. No ions reverted to the shale sample as the electric equilibrium was established. This paper would contribute immensely to the classification of different micro-fracturing features, and their characteristics for the distinct shale mineralogies.

Hydraulic fracturing is widely applied to develop tight oil reservoirs, and it is significant to diagnose fracture hit to determine optimal well spacing. Pressure test is an effective method to determine fracture hit in a multi-well system. In this study, we developed a semi-analytical model to quickly identify fracture hit in multiple vertical well system in tight oil reservoir. This semi-analytical model involves several steps, i.e., prior production step of parent wells, pressure build-up step, and interference test step. The model was verified by a numerical reservoir simulator for single well and multiple wells. Then, based on the model, the well interference by fracture hit in a three-well system (two parent wells and one child well) is discussed. Results show that the developed semi-analytical model could efficiently simulate the entire production process of a multi-well system, quickly diagnose fracture hit by using pressure interference test data and determine the optimal shut-in time of parent well. The practicability of model lies in that the reservoir pressure depletion by prior production of parent wells is considered. Besides, it is found shutting down the parent well is very necessary to diagnose fracture hit when the child well is infilled. When the shut-in parent well is connected to producing child well, the pressure build-up process of parent well is terminated with the bottom hole pressure reducing continuously. What is more, the shut-in time of parent wells should be sufficient to better detect the fracture hit, especially under the condition that parent wells have produced for a long time or the connectivity among wells is weak. This work can provide critical insights into understanding the mechanism of well interference by fracture hit in a multi-well system.

Supercritical carbon dioxide (CO 2 ) jet-assisted radial drilling is regarded as a potential alternative drilling method because supercritical CO 2 jet has higher efficiency in rock-erosion efficiency than water jet. Although researchers have investigated how the rock-erosion performance by supercritical CO 2 jet impingement correlates with the influencing parameters, there is little on the rock failure mechanism and change of pore structure. Scanning electron microscopy (SEM) analysis has been an important means in mineral identification, material damage detection, and aiding in water jet research. Therefore, rock-erosion experiments and SEM observations and analyses were carried out on different rocks including sandstone, marble and so forth. Secondary electron (SE) images show obvious grain shapes on the complex impinged surface of sandstone and marble by supercritical CO 2 jet, and cleavages on the mineral grains, and cracks and holes between the grains in different sizes. It suggests that cementations in weaker rocks are firstly removed and then mineral grains broken, generating the intergranular and intragranular cracks and micro-fractures and fissures. Supercritical CO 2 jet cannot bring obvious changes to hard limestone and shale at the same condition because the rock substances are tightly packed and filled with large cementing forces and ultra-low permeability and porosity, but can produce a few micro-cracks vertical to bedding planes. The features show that supercritical CO 2 jet broke rock substances mainly in the brittle tensile failure mechanism and made the rock much easier to further break, accompanied with shear failure mechanism in particular locations of the perforation hole. In contrast, water jet impingement forms flat cutting sections in marble with continuous parallel breaking traces, indicating the shear failure mechanism. Low viscosity and high diffusivity of supercritical CO 2 are primarily attributed to the rock tensile failure mechanism, they facilitate supercritical CO 2 penetrates into deep into rock pores and produces static pressure on the inner wall and at the tips of the fractures, besides exerting jet impinging pressure. Moreover, the energizing effect caused by the phase change from supercritical to gas leads to the energizing effect and intensify rock breaking into more shattered pieces and, concurrently, improve general rock connectivity and porosity in the surface layers. As a consequence, supercritical CO 2 jet appears to be more efficient and suitable than water jet in slim-hole radial drilling and hydraulic fracturing, particularly in unconventional reservoirs with low permeability.

Natural gas flow in shale matrices consisting of both organic and inorganic components was modeled using fractal concepts. The expression of the apparent permeability (AP) of such shale systems was derived following three main steps: (a) modeling real gas flow in a single pore by generalizing our previously reported Extended Navier-Stokes Equations method, then (b) using fractal theory concepts to obtain the apparent permeability for both the organic and inorganic-matter cells, and finally (c) upscaling the AP model to the sample scale, accounting for the heterogeneous distribution of the organic matter. The up-scaled AP model is more realistic, because it considers not only the varying cross-section shapes and tortuosity of the pores, but also the characteristic flow mechanisms and multi-scale pore size distribution in heterogeneous shale matrix systems. The model was successfully validated with experimental data from real samples. The effects of the organic matter and shape of the pores on the AP are investigated. The sensitivity of the AP to the total organic carbon (TOC), porosity, pore shape, and structural parameters of both organic and inorganic systems is studied. The results indicated that the AP would be overestimated by up to 24.1% if the characteristics of the organic matrix are ignored, and the AP proves more sensitive to the effect of the pore shape in the inorganic matrix. In addition, the top three key parameters affecting the AP are pore shape, maximum pore diameter in the inorganic matrix, and porosity. The AP is more sensitive to the pore size within the inorganic matrix than within the organic matter. The proposed model provides some theoretical and technical support for shale gas simulations.

Understanding spontaneous imbibition of fracturing fluid in shale is critical for hydraulic fracturing design and optimization. In this paper, we present an analytical model for spontaneous imbibition including a hysteretic relative permeability-saturation-capillary pressure (k-S-P) relation and evaluate the relevance of hysteresis effect when modelling fracturing fluid imbibition. In the hysteretic formulations, capillary pressure and relative permeability depend not only on the current saturation but also on the history of saturation in the invaded zone. Herein, we concentrate on fracturing fluid imbibition into shale matrix during shut-in time after refracture treatment, which is driven by the strong capillary forces present in the tight matrix. We demonstrate the importance of accounting for the hysteresis in capillary pressure and relative permeability for predicting the imbibed volume of a fracturing fluid. For a problem that involves drainage and imbibition cycles, a hysteretic k-S-P relation is required to accurately assess the distribution of fluid saturation in the invaded zone. We also demonstrate that although the difference in viscosity between the fracturing fluid and gas is large, the viscosity of the gas cannot be neglected in modelling fracturing fluid imbibition in shale. The results of this investigation are expected to provide a better understanding of fracturing fluid imbibition in shale.

It is reported that supercritical carbon dioxide (SC-CO2) jet can efficiently erode rocks at a comparably low threshold pressure with high penetration rate. However, the influences of bottom-hole pressure and borehole irregularities on SC-CO2 jet cutting efficiency have not been studied. Therefore, in this research, comprehensive methods of numerical simulations and lab experiments were carried out to investigate the influences of the ambient pressure and the nozzle-to-target distance on the jet impinging pressure and perforation performance. Results show that, both the effective jet impinging pressure and the eroded depth of perforation hole notably decrease with the increase of the ambient pressure, when jet inlet pressure is constant. When the pressure difference between inlet pressure and ambient pressure is kept constant, the effective impinging pressure hardly changes with ambient pressure, but eroded depth increases at first and then decreases, bounded by the critical pressure of CO2. As the nozzle-to-target distance extends, both the depth and volume of the perforation hole decrease, and diameter of the perforation hole increases at first and then decreases. Under the research condition of certain pressure and temperature, a distance of 8 times the nozzle diameter is the critical distance that clarifies the different effect of nozzle-to-target distance on the hole diameter. Different features between using SC-CO2 jet and water jet, including the optimal distance for rock-erosion efficiency, are attributed to the difference in fluid properties. Further simulation results show that, unlike water, SC-CO2 fluid is compressible and it leads to specific variations of jet structure, namely the increase of length of SC-CO2 jet potential core, and flow type from non-submerged jet to submerged jet. As a consequence, under the simulated bottom-hole conditions, SC-CO2 jet is proven to be able to acquire high rock-erosion efficiency and the jet-assisted drilling rate at a larger application ranges. This research can promote the future application of SC-CO2 jets.

This paper investigates the influences of surface diffusion on shale-gas transport through our proposed model. The model simulates multiple flow mechanisms in Kerogen pores considering surface diffusion, its impact on slippage velocity, and nonlinear assembly of viscous flow and Knudsen diffusion contribution. Further, an improved gas slippage model was developed considering the additional viscous flux produced by surface diffusion. A sensitivity analysis was carried out using real Kerogen properties to identify the contributions of surface diffusion to gas permeability. The results show that surface diffusion gradually becomes a primary contributor to gas production with decreasing pore pressure and pore diameter and increasing surface diffusivity and adsorbed capacity of Kerogen. In particular, surface diffusivity and pore diameter are the two most important factors for surface diffusion. However, the importance of surface diffusion is only valid in the cases satisfying certain conditions. In this study, the influence of surface diffusion becomes strong and must be accounted for when the surface diffusivity exceeds 1E-7 m2/s and the pore diameter is less than 5 nm.

Coupled gas flow and solid deformation in porous media have received considerable attention because of their importance in shale gas transport. The existence of propped and un-propped fractures makes simulating the complex flow more difficult in fractured shale reservoirs. The effect of matrix deformation on production has been ignored in most previous studies. Moreover, the influence of fracture conductivity loss has not been well studied in shale reservoirs with discrete fractures. In this study, a general porosity model and a correlation of fracture permeability loss are introduced to develop a fully coupled gas flow and deformation model that contains the shale matrix and discrete fractures. The numerical hydra-mechanical model is implemented using a finite element method and it is validated using an analytical solution with the simplified condition. The coupled model with discrete fractures is verified by reducing the fracture conductivity and comparing the results with the continuous model. Then the effects of the stress-dependent permeability of the matrix and fracture on cumulative production are analyzed. The numerical results indicate that the apparent permeability of shale gas is determined by both the effects of pore-compressibility and the non-Darcy flow. The intrinsic permeability decreases as the effective stress increases, while the apparent permeability can be enhanced because of the non-Darcy flow effect as the gas pressure is depleted. The ignorance of geomechanics about the matrix will lead to an overestimated cumulative production. The loss of fracture conductivity, including both the propped and un-propped fractures, impairs the production distinctly only when the dimensionless conductivities are small. Improving the fracture conductivity can offset the negative effect of conductivity loss on the cumulative production.

Hydro-jet fracturing is a unique hydraulic fracturing method, and has been recognized worldwide as an effective well-stimulation method for oil and gas production. However, because of controversy about the method's impact on water consumption and environmentally quality, hydraulic fracturing faces increasing restrictions. The demand for decreased water usage has promoted research on the use of non-aqueous fracturing fluids. In particular, the idea of using supercritical carbon dioxide (SC-CO2) fluid has attracted a lot of interest. Using SC-CO2 as a fracturing fluid is more effective and has significant advantages compared with water-based fluids. The unique properties of the SC-CO2 fluid facilitate fracture propagation, formation of complex fracture networks, and elimination of flow blockage in the rock matrix and pores. Therefore, the SC-CO2 jet fracturing technique may effectively enhance oil and gas recovery. Similar to hydro-jet fracturing, the pressurization effect in the perforation tunnel is a key precondition for successful jet fracturing with SC-CO2. This study investigated these effects using numerical simulations and experimental studies. Our results show that the pressurization effect during SC-CO2 jet fracturing improves with an increase in pressure difference, ambient pressure, nozzle diameter, and fluid temperature. However, pressurization becomes weaker with increasing casing hole diameter and annulus spacing. Comparing SC-CO2 and water jet fracturing pressurization effects suggests that using SC-CO2 jetting has advantages over water jet fracturing under in situ reservoir conditions. As the working depth increases, SC-CO2 jet fracturing achieves better pressurization than the water jet. The novel approach in our preliminary study begins to prove the feasibility of applying SC-CO2 jet fracturing to leverage unconventional resources.

Radial horizontal jet drilling technology is designed to provide multiple lateral micro-holes to enhance petroleum production by using high-pressure water jets to break the rock formation. The micro-hole length is a key parameter in this technology, and it has a significant influence on the design of drilling operation and petroleum production. This paper presents a model for calculating the maximum drillable micro-hole length by combining a theoretical analysis and experimental methods. The pressure loss of the circulation system, the pressure and flow rate of the pump, and the self-propulsion effect of the multiple-jet nozzle are included in the model. The results indicate that the flow rate is the dominant factor in the radial horizontal jet drilling process, and a high flow rate contributes to the creation of long micro-holes. The jetting force generated by multiple water jets is the only propulsion used to elongate the micro-hole. However, the friction of the flexible hose moving in the diverter and micro-hole is the main resistance limiting the length of the micro-hole. A comparison of this model with a field case result indicates that the model is sufficiently accurate for predicting the maximum drillable length of the micro-hole. The model and results presented in this paper can provide guidelines for the design of radial horizontal jet drilling operations.

Radial horizontal drilling technology can create several drainage micro-holes to improve the efficiency of fluid flowing from the reservoir into the wellbore, increase the single-well production rate and enhance the recovery of natural gas. This paper proposes a steady-state model to calculate the production rate of natural gas for radial horizontal micro-holes by coupling the reservoir inflow model and the wellbore flow model. The newly developed model calculates the friction pressure loss for gas flow in the radial horizontal wellbore. The influences of certain wellbore parameters on gas production rate have been analyzed, and a sensitivity study has been performed. The results show that the production rate increases as the wellbore length, the number of micro-holes, the included angle and wellbore diameter increase. However, the effects of the number of micro-holes, the included angle and the wellbore diameter are significant only within certain limits. Based on the degree to which the parameter positively affects the gas production rate, the wellbore parameters can be ranked as follows: wellbore length > the number of micro-holes > included angle > wellbore diameter > distance between the micro-hole and the lower boundary. The wellbore length and the number of micro-holes have the greatest influence on the production rate of multiple radial horizontal micro-holes. The models and results presented in this paper can provide the theoretical basis for the design of radial horizontal drilling in natural gas reservoirs.

Rock breaking with SC-CO2 has the advantages of low threshold pressure and high rate of penetration, so it has attracted full attention. In order to clarify the law of rock breaking with SC-CO2 jet, and enable it to serve SC-CO2 drilling better, the SC-CO2 jet system for rock breaking was used to carry out the experiments, which demonstrated that jet pressure, jet temperature, confining pressure, jet distance, rotary speed of core samples and jet time are the main factors to influence the rock-breaking performance and efficiency. The results showed the effects as follows. Jet pressure and confining pressure are the direct factors to affect rock-breaking performance. With the increase of jet pressure, the rock-breaking efficiency increases gradually, while as the confining pressure increases, it decreases with constant jet pressure or has the maximum around the critical jet pressure with constant pressure difference. With the increase of jet temperature, the efficiency increases at first and then decreases, and the relationship curve showed in parabolic function. Under the experimental conditions in this paper, the optimal jet distance is about 3–4 times of nozzle diameter. The rotary speed of core sample has no substantial influence on the erosion depth, but on the average width or diameter of eroded grooves. The average width and the size of the eroded cuttings are smaller when the rotary speed is higher. The erosion depth increases but the trend gradually decreases with the jet time being prolonged.

The most distinct feature of liquid nitrogen fracturing is the sharp reduction in temperature around the rock when liquid nitrogen comes in contact with the reservoir. This condition induces thermal stress inside rocks, which then become damaged. To investigate the effect of liquid nitrogen super-cooling on coal damage, permeability tests were conducted on the same coal samples before and after cooling. Meanwhile, uniaxial compression tests were performed on intact and cool-treated coal samples. Experimental results showed that liquid nitrogen super-cooling not only induces thermal cracks on coal surface, but also causes coal cracking along macro-fractures on the surface of samples. Coal permeability was increased by 48.89%–93.55% because of liquid nitrogen super-cooling. The compressive strength of cool-treated coal samples decreased by 16.18%–33.74% compared with intact samples, and the former presented more obvious brittle failure characteristics. In the uniaxial compression tests, the numbers of points in which stress induced a sharp decrease in the stress–strain curves of cool-treated samples were more than those in the intact samples, which indicates enhanced micro-fracturing in the cool-treated samples. Thus, we can conclude that liquid nitrogen super-cooling may cause coal damage and fracture failure, consequently promoting the formation of fracture networks and improving stimulation performance because of the generation of thermal fractures.

As liquid nitrogen brings about thermal damage to rock when it comes into contact with a reservoir, it can be used as a fracturing fluid under proper engineering conditions. To investigate the effects of liquid nitrogen cooling on rock pore structure, sandstone, marble, and shale samples were cooled with liquid nitrogen under dried and saturated conditions, respectively. The samples were examined before and after treatment using scanning electron microscopy and nuclear magnetic resonance. The results show that there are three main changes in the rock pore structure when the samples were cooled by liquid nitrogen: (i) a reduction in the number and volume of the pores, (ii) an expansion of the micro-fissures (micro-pores), and (iii) an increase in the pore scale. More specifically, the pore structure of dry sandstone showed a reduction in the number and volume of pores; dry and saturated marble and shale presented expansion of their micro-fissures (micro-pores); and the pore scale was increased in the saturated sandstone (to the extent that macro-cracks were observable in the surface). The changes in the rock pore structures were mainly caused by thermal stress and frost force, and the characteristics of the variations were influenced by the type of rock and water content. Liquid nitrogen cooling increased the fracture degree inside the rocks, especially for shale samples. Cracks appeared along the joints, which were effective in producing micro-cracks on the walls of major fractures. This therefore increased the stimulation reservoir volume during the fracturing process.

Summary Horizontal-wellbore cleanout by rotating jets and annular helical flow has developed rapidly in past decades, in which the annular helical flow is one of the most significant factors to transport the solids in a horizontal wellbore. Because of its complexity and lack of research approaches, the mechanism and characteristics of annular helical flow by high-pressure jets were never revealed comprehensively. By the computational-fluid-dynamics (CFD) method, the flow field of annular helical flow (such as its generation, continuation, and attenuation) was first manifested. The axial velocity and tangential velocity vary regarding cleaning distance, flow rate, and nozzle assemblies. Furthermore, the dynamic simulation of sandbed sweeping by rotating jets and annular helical flow in a horizontal wellbore was accomplished, and the influences on sweeping efficiency were discussed. Finally, the recommended nozzle assembly and its flow-rate distribution in front jets, lateral jets, and rear jets were provided. This study is beneficial in designing the cleaning tool and in optimizing the hydraulic parameters and operation procedures.

Acid fracturing in deep carbonate reservoirs is challenged by deep well stimulation with high temperature (>120 °C), high fracture pressure (>2.0 MPa/m), high flow friction, and strong reservoir heterogeneity. To meet these challenges, a new stimulation method, called the hydraulic jet acid fracturing technique, was developed. According to the mechanisms of hydraulic jet acid fracturing, the authors self-design the downhole injector and pipe strings used in multistage hydraulic jet acid fracturing and provide optimization standards for the nozzle number and diameter combination, abrasive perforating parameter, and pumping program. The technique realizes multistage acid fracturing by hydraulic separation and features simple downhole tools, high temperature resistance (160 °C), low cost and risk. In addition, hydraulic acid injection can extend effective acid corrosion distance nearby well and enhance the acidification effect. The optimal jet phasing is 60 degrees with spiral arrangement to lower formation fracture pressure. A relationship chart between optimal flow rate and wellhead pressure is established, which helps to increase flow rate as far as possible under wellhead assembly capacity and to determine nozzle diameter and number. Results from field tests show that this method can work at a maximum depth of 6 400.53 m, with a total acid volume of up to 618 m3. It is effective in creating acid fractures in ultra-deep horizontal wells. Key words: horizontal well, deep formation, water jet, multistage acid-fracturing, field test

In recent years, rapid progress in the use of high pressure water jets (HPWJ) has been made in oil and gas well drilling, completion, and stimulation; and good results have been achieved in field applications. Advances in technologies and developments of well completion and stimulation with hydrajet are reviewed in this paper. Experiments were conducted to study the characteristics of abrasive water jetting and to optimize jet parameters, which can provide methods for the well completion and hydrajet fracturing. Deep-penetrating hydrajet perforating can create a 2–3 m clean hole with a diameter of 20–35 mm. Multilayer hydrajet fracturing is a process whereby multiple layers are stimulated in a single run without using mechanical packers, thereby reducing operation procedure and risk. Multilateral radial wells can be drilled using hydraulic jetting up to 100 m in length. The technique to remove sand particles and plugs with rotating self-resonating cavitating water jets in horizontal wellbores has been developed and oilfield-tested, which shows promising, cost effective prospects.

A numerical model and transmission characteristic analysis of DPSK (differential phase shift keying) pressure signals in mud channels is introduced. With the control logic analysis of the rotary valve mud telemetry, a logical control signal is built from a Gate function sequence according to the binary symbols of transmitted data and a phase-shift function is obtained by integrating the logical control signal. A mathematical model of the DPSK pressure signal is built based on principles of communications by modulating carrier phase with the phase-shift function and a numerical simulation of the pressure wave is implemented with the mathematical model by MATLAB programming. Considering drillpipe pressure and drilling fluid temperature profile along drillpipes, the drillpipe of a vertical well is divided into a number of sections. With water-based drilling fluids, the impacts of travel distance, carrier frequency, drillpipe size, and drilling fluids on the signal transmission were studied by signal transmission characteristic analysis for all the sections. Numerical calculation results indicate that the influences of the viscosity of drilling fluids and volume fraction of gas in drilling fluids on the DPSK signal transmission are more notable than the others and the signal will distort in waveform with differential attenuations of the signal frequent component.

When perforating with an abrasive water jet, it is possible that the pressure in the hole (perforation) will be higher than that in the annulus because of water jet blasting against the hole wall, which also is the theoretical basis for the technology of hydro-jet fracturing. This paper analyzes the mechanism of generating pressure stagnation in water jet hole, and puts forward a new concept of hydroseal. Then, the distribution of pressure in the hole was simulated with the finite element method. The simulation results showed that the pressure in the hole was higher than that in the annulus. Also, the lower the annular pressure (confining pressure) and the higher the blasting pressure, the greater the pressure difference. An experiment indicated that the cement sample was lifted up under the pressure stagnation in the hole, which proved the finite element simulation results obviously.