Multistage Hydraulic Fracturing Research Articles

A new analytically modified embedded discrete fracture model for pressure transient analysis in fluid flow

In the past few decades, multi-stage hydraulic fracturing has emerged as a crucial technology for the commercial development of unconventional oil and gas (UOG) resources. It is crucial to accurately and efficiently characterize transient fluid flow near fractures, which is a critical concern for many researchers. Discrete fracture models (DFMs) are primarily used to analyze the pressure transient behaviors of fluid flow in naturally fractured porous media. DFMs can accurately capture transient fluid flow near fractures, but they require a substantial number of grids to ensure computational accuracy, leading to higher computational costs. On the other hand, standard embedded discrete fracture models (EDFMs) based on pseudo-steady-state assumptions are computationally efficient, but they struggle to model the early transient fluid flow near fractures accurately. To address this limitation, we propose a new analytically modified EDFM (AEDFM) with structured Cartesian grids for analyzing the pressure transient behaviors of fluid flow in naturally fractured porous media.The transmissibility between the matrix and fractures is adjusted by multiplying it with a transient factor. In addition, we have validated the accuracy and efficiency of our proposed model through comparisons with results from analytical models and a standard well-testing software package. The results demonstrate the significance of our proposed model in accurately capturing transient fluid flow around fractures and reducing computational costs. In this work, we analyze the pressure transient behaviors of fluid flow using various parameter values and further evaluated the significance of the proposed modifications. The results indicate that AEDFM can effectively match the early nonlinear pressure drop near fractures compared to the standard EDFM. This work presents a powerful tool for the fast and accurate analysis of pressure transient behaviors of fluid flow in naturally fractured porous media.

The influence of hydraulic fracture and reservoir parameters on the storage of CO2 and enhancing CH4 recovery in Yanchang formation

The demand for a clean energy source from shale is growing day-to-day since it is not harmful to the environment like other fossil fuels. Further, shale reservoirs offer long-term geo-carbon dioxide (CO2) storage. Innovations in horizontal drilling and multi-stage hydraulic fracturing have made shale gas extraction and geo-CO2 storage economically viable. A three-dimensional Yanchang shale formation simulation model in Ordos's basin was developed using CMG-GEM, considering adsorption/desorption, diffusion, geomechanics, permeability changes, and non-Darcy flow. Two horizontally drilled wells, each 510 m long, were fractured and positioned 90 m apart. CO2 gas was injected into Well-2, producing methane (CH4) in Well-1. After simulation for 30 years, the cumulative mass of CH4 produced was 1.07×10+5kg, the cumulative mass of CO2 produced was 2.3×10+4kg, which is 1.14% of the mass injected, the cumulative mass of CO2 injected was 2.01×10+6kg and cumulative mass of CO2 gas stored was 1.987×10+6kg which is 98.86% of the injected mass of CO2 gas. The natural fracture system was the dominant factor of enhanced shale gas recovery and CO2 injection in the Yanchang shale formation. A sensitivity analysis was conducted with CMG-CMOST, examining the influence of reservoir and hydraulic fracture parameters in the storage of CO2 and enhancing CH4 recovery. Natural fracture porosity had the most significant impact on CH4 production and CO2 storage, followed by fracture permeability and half-length leading for hydraulic fracture parameters, with fracture conductivity being the least influential parameter. The approach used in this study applies to tight shale oil and gas formations in various sedimentary basins worldwide, enabling a more comprehensive understanding of reservoirs and hydraulic fracture parameters that can enhance oil and natural gas production.

A three-dimensional numerical well-test model for pressure transient analysis in fractured horizontal wells with secondary fractures

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.

Coupling model of gas-water two-phase productivity calculation for fractured horizontal wells in tight gas reservoirs

Tight gas reservoirs are exploited mostly by using horizontal wells in combination with multi-stage hydraulic fracturing. Up to now, there have been plenty of studies conducted to establish a series of productivity models that consider various factors. Despite this, insufficient consideration has been given to the ramifications resulting from secondary fractures, permeability anisotropy, wellbore pressure drop, and the actual distribution of fractures. To accurately evaluate productivity, the superposition principle of potential and the conformal transformation theory are adopted to define the two-phase generalized pseudo-pressure, with consideration given to the characteristics of non-Darcy seepage in tight gas reservoirs and the effects of secondary fractures and permeability anisotropy on productivity. On this basis, the homogeneous flow model of the horizontal wellbore is introduced to establish the coupling model of gas-water two-phase productivity calculation for fractured horizontal wells. The results obtained from the empirical calculation and analysis of various factors affecting productivity are as follows. Firstly, the relative error is 5.35% between the theoretical open flow capability obtained from the proposed model and the open flow capability determined through the deliverability test, which attests to the proposed model's accuracy. Secondly, in response to an increase in gas slippage factor, fracture conductivity, the number of fractures, and the degree of permeability anisotropy, there is an improvement in the productivity of the gas well. However, with a rise in the water-gas volume ratio, threshold pressure gradient, reservoir stress sensitivity index, and the angle formed between the horizontal wellbore and the main permeability, the productivity declines. Lastly, the pressure drop along the horizontal wellbore is relatively insignificant, which has no substantial impact on fracture production. However, when the effect of secondary fractures is ignored, the predicted productivity is relatively low. This study offers theoretical direction for the application of productivity prediction and fracturing optimization design.

Multi-stage hydraulic fracturing simulation methodology at the wells of the gas condensate field X

The purpose of this work is to select the optimal method for multi-stage hydraulic fracturing simulation at the wells of a large gas condensate field X in conditions of low-permeability reservoirs and potential risk of condensate loss in the near bottomhole zone with a decrease in reservoir pressure. At the moment, there are many ways to simulate hydraulic fracturing, each of which is characterized by its advantages and disadvantages. For specific simulation conditions, it is necessary to choose the most optimal method of hydraulic fracturing simulation, which allows you to correctly simulate all the effects that are expected during development. Within the framework of the current work, the most common numerical methods of hydraulic fracturing simulation were described in abstract, their advantages and disadvantages for specific conditions of field X were reflected. Special attention was paid to the comparison of hydraulic fracturing simulation techniques using virtual perforations and local grid refinement, since these techniques are the most common ways to set hydraulic fracturing in existing hydrodynamic simulators. Scenario calculations were carried out, which made it possible to determine the limits of applicability of various methods, compare the correctness of reproducing downhole effects, quantify the deviation of the calculation results of different methods from the reference calculation. In addition, in the course of the work, various features of the application of the hydraulic fracturing simulation through local grid refinement were described, which were revealed experimentally. As a result, for multi-stage hydraulic fracturing simulation was used a method in which the cells with hydraulic fracturing are logarithmically chopped relative to the original grid. This method allows to simulate the actual rate of decline in well productivity in conditions of low reservoir permeability, and also allows to simulate in the hydrodynamic model the effect of condensate precipitation in the near bottomhole zone and the subsequent decrease in gas productivity.

ANALYSIS OF THE EFFECTIVENESS OF STIMULATION METHODS AT THE TRIZ FACILITY — PREOBRAZHENSK PETROLEUM PRODUCT HORIZON, EASTERN SIBERIA

The history of prospecting and exploration of oil and gas fields within the Nepsko-Botuoba Anteklisa (NBA) and the eponymous oil and gas region (OGR) of the Leno-Tunguska Oil and Gas Province of the Siberian Platform dates back more than half a century. The base object of exploration for a long time remained the terrigenous deposits of the Venda reservoir. A number of large, medium and small hydrocarbon deposits are associated with them. The beginning of a systematic study of the northern regions of the Irkutsk region was the receipt of oil inflow from the Markov reference well in 1962. In 1971, the Yaraktinskoye gas condensate field was discovered north of Markovsky. In 1970, a parametric well was drilled within the Preobrazhensky uplift, which made it possible to identify a productive carbonate horizon (Zone B12), from which a gas inflow was obtained after hydrochloric acid treatment. Further continuation of the complex of geophysical studies east and south of Preobrazhenskaya Square made it possible to identify a number of positive structural forms. In the Chonsky zone, several local complications were identified — Chonsky, Molchalunsky and Verkhnechonsky structural noses, recommended for setting up area studies of MOU. The Preobrazhensky horizon (Zone B12) ranks second among the pay zones in terms of potential in-place reserves. It is the extremely low filtrationcapacitive properties of the natural reservoir and the harsh thermobaric conditions at the pressure of oil saturation with gas close to the initial reservoir pressure that is the basis for classifying these reserves as hard to recover (RHR).This article discusses the methodological features of drilling and completion of oil producing wells with a horizontal end of a long length, ascending inclined boreholes, multi-hole horizontal wells (MHW), conducting MHW, large-volume MKO and KGRP in the carbonate natural reservoir of the Preobrazhensky productive horizon (B12) of one of the fields of the Nepsky arch in the north of the Irkutsk region. The oil reserves of this tank are classified as difficult to recover (RHR). Research and search for new approaches to the development of the TRiZ facilities of the Preobrazhensky carbonate horizon in this field is today the most important task. The main results of the testing of the complex of geological and technological measures (GTM) are summarized, including a new effective technology for conducting multi-stage hydraulic fracturing, which is planned for use in the further full-scale development of the oil reservoir.

HORIZONTAL WELL COMPLETION SYSTEMS WITH MULTI-STAGE HYDRAULIC FRACTURING FOR LOW-PERMEABILITY, POORLY DRAINED, HETEROGENEOUS AND DISMEMBERED RESERVOIRS

Currently, the most effective method of intensifying the inflow of hydrocarbons and increasing oil recovery in productive formations in wells, in particular with a horizontal well, remains the technology of hydraulic fracturing (HF). In many regions, according to some domestic and foreign researchers, this is the only technology for developing fields with hard-to-recover hydrocarbon reserves confined to lowpermeability, poorly drained, heterogeneous and dissected reservoirs, which can significantly increase hydrocarbon production and make wells economically viable.Multi-stage hydraulic fracturing (MSHF) has established itself as one of the main methods of reservoir stimulation in the Russian Federation. The main goal of this method is to create highly conductive fractures in an oil and gas saturated reservoir throughout the horizontal section of the wellbore. To do this, an alternate series of hydraulic fracturing is performed, the result of which is the maximum production rate of hydrocarbons.Over time, oil and gas companies in the Russian Federation are becoming more demanding on the technical and technological parameters of MSHF in terms of the number of stages, the length of the horizontal section of the well, the possibility of re-fracturing and management of intervals/ports after its commissioning, and much more.The authors of the article propose to consider and analyze modern horizontal well completion systems with multi-stage hydraulic fracturing for low-permeability, low-drainage, heterogeneous and dissected reservoirs in order to form their rating.

How Injection History Can Affect Hydraulic Fracturing–Induced Seismicity: Insights from Downhole Monitoring at Preston New Road, United Kingdom

ABSTRACT In August 2019, a multistage hydraulic fracturing (HF) operation was carried out at Preston New Road, United Kingdom. HF caused abundant seismic activity that culminated with an ML 2.9 event. The seismic activity was recorded by a downhole array of 12 sensors located in a nearby monitoring well. About 55,556 events were detected and located in real time during the operation by a service company. In this study, we first improve the number of detections by applying template matching and later calculate the moment magnitude of the associated earthquakes. Then we show that by separately analyzing the periods during and immediately after injection, distinct patterns can be identified. We observe an increase in the delay and decrease in amplitude of peak seismicity during subsequent phases of injection. After injection, the seismicity decay can be described by the Omori–Utsu law. The decay rate tends to slow with each successive injection, in particular during the later injection stages. In addition, the frequency–magnitude distribution evolves from a tapered distribution (lack of large events) to a bilinear distribution (excess of large events). This evolution is gradual, with the corner magnitude increasing with each injection. We interpret these patterns as the result of the combined effect of two factors: (1) the stimulated volume becoming increasingly aseismic and (2) the gradual increase in its size, which increases the probability of triggered events on preexisting faults. More generally, these patterns suggest that seismic activity during injection is strongly influenced by the injection history and is modulated by local conditions such as stress state, fault structure, and permeability.

Analysis of dynamic thermal behaviors for multi-stage hydraulic fracturing treatments in horizontal shale oil and shale gas wells

Accurate prediction of dynamic thermal behaviors during multi-stage hydraulic fracturing is profound which can avoid performance deterioration of fracturing fluids or failure of fracturing tools caused by severe temperature variation. This paper establishes a transient heat transfer model for multi-stage hydraulic fracturing in horizontal shale oil and shale gas wells (MFHWM), considering the real construction process of multi-stage hydraulic fracturing, the turbulent flow state, the heat source of viscous dissipation and the complex wellbore structure, which enables the accurate simulation of thermal behaviors in the early time of multi-stage hydraulic fracturing with large flow rate. The verification results of measured temperature data and simulation data prove the MFHWM has good precision. Numerical simulations indicate that the temperature distribution exhibits the characteristics of cyclic “cool-down” and “warm-back” and “stair-step” during the multi-stage hydraulic fracturing. In the “cool-down” period, the temperature drops sharply within the first hour and then the deceleration slows down. In the “warm-back” period, the temperature recovers exponentially relying on the shut-in time. The “stair-step” is caused by changing of heat transfer mechanism from convection to conduction. Moreover, the cyclic cooling has little effect on the total temperature drop and subsequent stages are not significantly cooler than previous stages. Besides, primary factors affecting temperature distributions of wellbore-formation system are discussed thoroughly. Results indicate that the viscous heat source cannot be ignored for multi-stage hydraulic fracturing and the temperature difference exhibits cyclic variation when considering and without considering the viscous heat source. In addition, the minimum temperature during each-stage-fracturing operation decreases first and then increases as the injection rate of fracturing fluid increases because of the compromise between the viscous heat source and forced convection. Furthermore, temperature distributions can be controlled by changing the injection temperature of fracturing fluid. As the injection temperature increases, a positive proportional relationship exists between the minimum temperature of fracturing fluid and the injection temperature. MFHWM can be a standalone tool to analyze temperature distributions of multi-stage hydraulic fracturing. It can also be used to provide better boundary conditions for stress analysis model of casing and cement sheath.

Analysis of the Application of Marked Proppant When Carrying Out Multistage Fracturing of the Object YUV1

The article analyzes the results of using the inflow monitoring technology in GeoSplit horizontal production wells, the essence of which is the use of quantum marker-reporters, which are sources of accurate information about the inflow of water and oil. One of the ways to place markers in a well is to mix them with a proppant base during multi-stage hydraulic fracturing. This technology makes it possible to obtain information about the inflow for each multi-stage hydraulic fracturing interval over a long period of time.

Promoting the uniform propagation of multi-fracture through adjusting the injection rate and perforation parameter: A numerical study

The strong stress interference and fluid competitive distribution result in the non-uniform propagation of multiple fractures during horizontal well multi-stage hydraulic fracturing (HWMHF). The uniform stimulation effect can be effectively improved by adjusting the injection rate and perforation scheme. In this work, a two-dimensional fluid–solid fully coupled multi-fracture propagation model is established to investigate the pattern of multi-fracture propagation and the flow distribution. The considering factors include the fluid injection rate, the perforation parameters, and the reservoir heterogeneity. The pipe element is developed to realize the free fluid distribution among multiple fractures. The results show that multiple fractures are more likely to initiate simultaneously and propagate uniformly with a higher fluid injection rate. The stress interference among multiple fractures can be balanced and the equilibrium propagation degree of multiple fractures can be greatly improved by reducing the perforation number. In the homogeneous reservoir, when the fluid injection rate is 12 m3/min and the perforation number per cluster is reduced to 10, the difference coefficient of fluid distribution can be reduced to 3.31%. In the heterogeneous reservoir, multiple perforation clusters with different tensile strengths can generate nearly uniform fractures by increasing the fluid injection rate and reducing the perforation number. When the fluid injection rate is 12 m3/min and the perforation number per cluster is 6, the difference coefficient of fluid distribution can be reduced to 3.26%. This work is of great significance in clarifying the propagation pattern and optimizing the fluid injection rate and the perforation number to improve the uniform propagation degree of multiple fractures.

PROBLEMS OF EVALUATION OF THE EFFICIENCY OF THE STIMULATION OF LOW-PERMEABILITY RESERVOIRS OF HYDROCARBONS

The article discusses the conditions for the formation of hydrocarbon deposits and their changes during the development of lowpermeability reservoirs, as well as the most effective technologies for developing deposits of this type, which help increase the coverage of residual hydrocarbon reserves. Low-permeability reservoirs are susceptible to foreign fluid damage, so it is necessary to continuously reduce damage throughout the fracturing process through the use of optimized fluid systems and process parameters. The most effective technologies are: the use of horizontal wells with multi-stage hydraulic fracturing, which ensures the largest volume of hydrocarbon recovery at the initial stage, the use of multilateral wells with branched horizontal ends when it is impossible to use multi-stage hydraulic fracturing. To increase the connectivity of flow channels and provide increased hydrocarbon production, the multi-stage hydraulic fracturing process damages low-permeability reservoirs. The fracture extends in height and length over tens of meters and, thanks to this, can provide hydrodynamic connection to formation zones remote from the perforation interval. Thus, the need for well research methods that are capable of recording formation performance regardless of the position of the secondary opening (perforation) interval is relevant

Experimental and Simulation Investigation on Ball-Sealer Transport and Diversion Performance Aided by Machine Learning Method

Summary Ball-sealer diversion has been proven to be an effective and economical way to increase fractures and fracturing volume in multistage hydraulic fracturing and matrix acidizing treatments. However, designing and implementing a successful ball-sealer diversion treatment is still challenging. Typically, operators rely on empirical data to determine diversion parameters and need an understanding of accurate ball transport and diversion behaviors. A model for optimizing operating parameters, including fluid and ball properties, and predicting the diversion performance of ball sealers before treatment is needed for designing the fracturing process. In this work, we systematically investigated ball-sealer diversion using experimental and numerical methods. The resolved model of computational fluid dynamics (CFD) and discrete element method (DEM) is first developed to simulate the transport of a large ball in a horizontal wellbore with side holes. The experimental results validated the numerical model. The effects of the ball position in the pipe, flow ratio of the hole to pipe, injection flow rate, and ball density on the diversion performance were studied under field parameters. The results show that the ball sealer easily misses the heel-side perforation due to the inertial effect and travels to the toe side due to the large inertia and turbulent flow. The ball position and flow rate ratio are crucial for the diversion performance. There is a threshold value of the ball position under the specific condition, and the ball successfully turns to the perforation only when the threshold distance is met. A ball sealer closer to the perforation will have a larger probability of blocking the hole than the ball at the other side of the wellbore. The larger the flow rate ratio, the more the drag force on the ball, and the ball can successfully divert to the perforation despite the ball being far from the hole. The injection flow rate and ball density negatively correlate with the diversion performance due to the large inertia and gravity. The best classification result with the F1 score of 87.0% in the prediction set was achieved using the random forest (RF) algorithm. It provides new insight into developing ball sealers and adjusting fracturing parameters based on machine learning (ML) methods.

Lab Experiments for Abrasive Waterjet Perforation and Fracturing in Offshore Unconsolidated Sandstones

Multistage hydraulic fracturing has been proven to be an effective stimulation method to extract more oil from the depleted unconsolidated sandstone reservoirs in Bohai Bay, China. The offshore wellbores in this area were completed with a gravel pack screen that is much too difficult to be mechanically isolated in several stages. Hydra-jet fracturing technology has the advantages of multistage fracturing by one trip, waterjet perforation, and hydraulic isolation. The challenges of hydraulic-jet fracturing in offshore unconsolidated sandstone reservoir can be summarized as follows: the long jet distance, high filtration loss, and large pumping rate. This paper proposes full-scale experiments on the waterjet perforation of unconsolidated sandstone, waterjet penetration of screen liners and casing, and pumping pressure prediction. The results verified that multistage hydra-jet fracturing is a robust technology that can create multiple fractures in offshore unconsolidated sandstone. Lab experiments indicate that the abrasive water jet is capable to perforate the screen-casing in less than one minute with an over 10 mm diameter hole. The water jet perforates a deep and slim hole in unconsolidated sandstone by using less than 20 MPa pumping pressure. Recommended perforating parameters: maintain 7% sand concentration and perforate for 3.0 min. Reduce sand ratio to 5%, maintain 3.0 m3/min flow rate, and continue perforating for 7.0 min. The injection drop of the nozzle accounts for more than 62% of the tubing pump pressure. The recommended nozzle combinations for different fracturing flow rates are 8 × ø6 mm or 6 × ø7 mm for 2.5 m3/min and 3.0 m3/min, and 8 × ø7 mm for 3.5 m3/min and 4.0 m3/min. A one-trip-multistage hydra-jet fracturing process is recommended to be used for horizontal wells in offshore unconsolidated sandstone reservoirs.

Development of fracture diagnostic methods for fluid distribution based on quantitative interpretation of distributed acoustic sensing and distributed temperature sensing

Multistage hydraulic fracturing design on horizontal wells has significantly evolved with larger fluid volume, more fracturing stages, and tighter perforation cluster spacing to efficiently stimulate unconventional reservoirs. From the published field observations, the recent fracturing design results in complex fracture networks or swarm of fractures. Fracture treatment evaluation is extremely challenging in such a case because of the large amount of variables in well completion and stimulation design. Combined measurements from different technologies can help in fracture diagnosis. Fluid distribution, either during fracture injection or during production, directly relates to the stimulation efficiency at the cluster level and at the stage level. Because it is unlikely in the real world to distribute the injected fluid uniformly among all the clusters, we need diagnostic techniques to generate the flow profile along a lateral. Fiber-optic measurements, such as distributed acoustic sensing (DAS) and distributed temperature sensing (DTS), are currently used to diagnose downhole flow conditions. This technology allows us to qualitatively confirm the fluid flow profile and other issues occurring downhole during fracturing such as leakage through plugs. For optimizing a fracturing design, we also need to understand how the design parameters are correlated with the stimulation efficiency. In this study, we combine two sets of models of DAS and DTS data interpretation for injected fluid volume distribution. The DAS is interpreted based on an empirical correlation between fluid flow rates and frequency band energy from the acoustic signals. The DTS is interpreted by performing temperature history match-based thermal energy conservation. Because of the completely different physics behind the interpretations, the confirmation of two interpretations provides confidence in fluid distribution.

Field investigation of multi-stage pulse hydraulic fracturing for improving permeability of coal seam in directional long borehole in underground coal mines

Field investigation of multi-stage pulse hydraulic fracturing for improving permeability of coal seam in directional long borehole in underground coal mines

Accurate Prediction of the Proppant Distribution in a Hydraulically Fractured Stage.

One of the greatest challenges in stimulating a single hydraulic fracturing stage with multiple clusters is ensuring that the proppant is equally distributed across all clusters. In this paper, the Buckingham pi theorem was applied to implement a dimensional analysis to establish an empirical correlation. The experimental correlation was developed by acquiring and integrating the data of various independent variables, such as different proppant characteristics (i.e., size, density, and concentration), using a wide range of internal diameters of the horizontal wellbore and multiple perforation configurations, and utilizing many carrier fluids with different viscosities. This work presents a newly enhanced experimental correlation for the distribution of proppants by incorporating the effect of gravity on proppant particles. The correlation proved its reliability in forecasting the proppant distribution with an average percentage error of less than 10%. The developed correlation has the potential to serve as a tool for forecasting proppant distributions among multiple clusters in multistage hydraulic fracturing treatments in the field.

A Review of Macroscopic Modeling for Shale Gas Production: Gas Flow Mechanisms, Multiscale Transport, and Solution Techniques

The boost of shale gas production in the last decade has reformed worldwide energy structure. The macroscale modeling of shale gas production becomes particularly important as the economic development of such resources relies on the deployment of expensive hydraulic fracturing and the reasonable planning of well schedules. A flood of literature was therefore published focused on accurately and efficiently simulating the production performance of shale gas and better accounting for the various geological features or flow mechanisms that control shale gas transport. In this regard, this paper presents a holistic review of the macroscopic modeling of gas transport in shale. The review is carried out from three important points of view, which are the modeling of the gas flow mechanisms, the representation of multiscale transport, and solution techniques for the mathematical models. Firstly, the importance of gas storage and flow mechanisms in shale is discussed, and the various theoretical models used to characterize these effects in the continuum scale are introduced. Then, based on the intricate pore structure and various pore types of shale gas reservoirs, this review summarizes the multiple-porosity models in the literature to represent multiscale gas transport, and discusses the applicability of each model. Finally, the numerical and analytical/semi-analytical approaches used to solve the macroscopic mathematical model governing shale gas production are reviewed, with a focus on the treatment of the complex fracture network formed after multistage hydraulic fracturing.

Generation mechanism and influencing factors of fracture networks during alternate fracturing in horizontal wells

Hydraulic fracturing is an effective means to increase natural gas production, and alternating fracturing is a special fracturing method. Compared with sequential fracturing, alternating fracturing is easier to form complex fracture networks. In order to investigate the generation mechanism of complex fracture networks during alternate fracturing, we conducted several multi-stage hydraulic fracturing experiments indoors with different fracturing sequences. Based on the cohesive element method, a numerical hydraulic fracturing model was established, from which the stress interference affected by the fracture spacing and horizontal in-situ stress were analyzed. The results show that: Alternate fracturing is more effective in controlling fracture geometry than sequential fracturing, which is also advantageous in shortening fracture spacing and avoiding the penetration of adjacent fractures. The critical factors affecting the branch fractures are the fracture spacing and the number of main fractures. Alternating fracturing is easier to produce branch fractures perpendicular to the main fracture. The stress interference among main fractures will change or reverse the stress field. The branch fractures closed due to the competition mechanism at the fracture tip are reactivated and extended perpendicular to the main fracture. Alternate fracturing is beneficial in activating microfractures near the main fractures, especially under a larger stress difference. The number of micro-fractures activated by alternating fracturing was more 14% and 21% than the sequential fracturing with the stress difference of 3 MPa and 11 MPa. The increase in stress difference and fracture spacing will decrease the fracture fractal dimension, and the fractal dimension of alternating fracturing is 0.054 more than that of sequential fracturing.

Tight and Shale Oil Exploration: A Review of the Global Experience and a Case of West Siberia

Shale and tight oil reservoirs, with horizontal wells and hydraulic fractures, typically have a recovery ratio of around 10%. The exploration of tight oil and shale in North America has proven economically viable, thanks to advancements, such as horizontal wells, hydraulic fracturing, and other enhanced oil recovery techniques. Taking inspiration from the global experience (the North American shale experience), the exploration and development of the West Siberian tight and shale reserves was more focused on the reported best practices of the exploration of North American shale. In this study, the advance in the specific areas of shale and tight oil exploration was considered, with more emphasis placed on the progress in the exploration of West Siberian shales. According to the review literature, thermal enhanced recovery methods capable of converting organic matter into hydrocarbons were studied more than other methods of enhanced oil recovery. Aligned with global trends, there has been a growing focus on research aiming to integrate data-driven approaches and pore-scale simulations to enhance recovery from tight and shale formations. Multiple pilot studies have showcased promising prospects for implementing multistage hydraulic fracturing. Nevertheless, there are limited pilot studies dedicated to enhanced oil recovery methods for West Siberian shale.