Horizontal Fracture Research Articles

Optimization of Fracturing Parameters by Modified Genetic Algorithm in Shale Gas Reservoir

Shale gas reservoirs have extremely low porosity and permeability, making them challenging to exploit. The best method for increasing recovery in shale gas reservoirs is horizontal well fracturing technology. Hence, fracturing parameter optimization is necessary to enhance shale gas horizontal fracturing well production. Traditional optimization methods, however, cannot meet the requirements for overall optimization of fracturing parameters. As for intelligent optimization algorithms, most have excellent global search capability but incur high computation costs, which limits their usefulness in real-world engineering applications. Thus, a modified genetic algorithm combined based on the Spearman correlation coefficient (SGA) is proposed to achieve the rapid optimization of fracturing parameters. SGA determines the crossover and mutation rates by calculating the Spearman correlation coefficient instead of randomly determining the rates like GA does, so that it could quickly converge to the optimal solution. Within a particular optimization time, SGA could perform better than GA. In this study, a production prediction model is established by the XGBoost algorithm based on the dataset obtained by simulating the shale gas multistage fracturing horizontal well development. The result shows that the XGBoost model performs well in predicting shale gas fracturing horizontal well production. Based on the trained XGBoost model, GA, SGA, and SGD were used to optimize the fracturing parameters with the 30-day cumulative production as the optimization objective. This process has conducted nine fracturing parameter optimization tests under different porosity and permeability conditions. The results show that, compared with GA and SGD, SGA has faster speed and higher accuracy. This study’s findings can help optimize the fracturing parameters faster, resulting in improving the production of shale gas fracturing horizontal wells.

A Numerical Model for Pressure Analysis of a Well in Unconventional Fractured Reservoirs

Fractured reservoirs are highly heterogeneous in both matrix and fracture properties, which results in significant variations in well production. Assessing and quantifying the influence of fractures on fluid flow is essential for developing unconventional reservoirs. The complicated effects of fractures in unconventional fractured reservoirs on fluid flow highly depend on fracture geometry, fracture distribution, and fracture properties, which can be reflected in pressure transient testing. The biggest challenge lies in delineating the pre-existing natural fracture distribution pattern, density, azimuth, and connectivity. Using the advanced finite element method, this paper builds a finely characterized near-wellbore model to numerically simulate the pressure transient testing process in naturally fractured reservoirs and further evaluates fracture-related effects to obtain a more accurate solution. First, the numerical program is benchmarked by the analytical solutions and numerical results of Eclipse. Next, different fracture models with single fractures or fracture networks are set up to investigate the effects of fracture parameters numerically (e.g., fracture location, fracture dip angle, fracture spacing, the ratio of fracture permeability to matrix permeability, fracture network orientation, horizontal fracture distribution, etc.) on pressure transient behaviors in naturally fractured reservoirs. Velocity and pressure profiles are presented to visualize and analyze their effects, and new features in the flow regimes of the derivative plots of the bottom-hole pressure are identified and discussed. Finally, based on geological and geophysical data, including image logs, core descriptions, wireline logs, and seismic and well test data, a practical fractured model of the Dalwogan 2 well in the Surat basin is built, analyzed, and compared with homogenous and measured data. The results show significance in characterizing the complex fracture networks in near-wellbore models of unconventional fractured reservoirs.

On the Role of Gravity in Dissolving Horizontal Fractures

AbstractFractures are ubiquitous in geological systems. As reactive fluid flow through a fracture, dissolution of the fracture walls may occur, thus altering the fracture aperture and increasing permeability. It has been recognized that gravity plays an important role in dissolving vertical fractures due to buoyancy‐driven convection. However, the role of gravity in dissolving horizontal fractures is not well understood. Here, we combine microfluidics/Hele‐Shaw experiments and a numerical method to study how the interplay of buoyancy‐driven convection and forced convection controls dissolution dynamics and permeability increase in horizontal fractures. We first develop the micro‐continuum approach by incorporating the gravitational effects, and then, we perform experiments to validate our method, confirming that the method can well capture gravitational effects on dissolution. Through 3D simulations, we find that buoyancy‐driven convection breaks the symmetry of dissolution on the upper and lower surfaces. We employ a symmetry index to identify three dissolution regimes. As the importance of gravity increases (Ri increases), the dissolution regime shifts from forced convection to mixed convection and to natural (or buoyancy‐driven) convection. We establish a link between these dissolution regimes and permeability evolution. In the forced convection or natural convection regimes, the permeability nearly remains unchanged for various Ri. However, in the mixed convection regime, permeability increase is suppressed by the gravitational effects; the underlying mechanism is that the solid phase tends to dissolve near the fracture inlet due to gravitational instability. This work improves our understanding of the gravitational effects on dissolution regimes and permeability evolution in horizontal fractures.

Case Study on the Effect of Acidizing on the Rock Properties of the Mahu Conglomerate Reservoir

The development of the Mahu tight reservoir has adopted horizontal wells with staged fracturing. In the fracturing, there is a problem of a high fracturing pressure. Acid treatment is often used to lower the fracturing pressure on site. At present, the impact of this acid treatment on the physical parameters of the rocks of the reservoir in the Mahu region has not been systematically studied. Aiming to solve this problem, this paper conducted an experimental study on how acid dissolution affects the physical properties of the Mahu conglomerate, including its porosity, permeability, triaxial rock mechanical parameters, tensile strength, and mineral composition. First, the experimental scheme was designed. Next, a series of experiments were conducted. Finally, the experiment results were analyzed comparatively before and after acidizing. The acid composition, concentration, and contact time were the main factors for the analysis, based on which the acid system and related parameters were recommended. This study showed that the Mahu conglomerate exhibited brittle plasticity characteristics under stress. The carbonate content in this region was low, while the feldspar content was high, so it was necessary to use mud acid to effectively dissolve feldspar, clay, and other silicates. After acidizing, the porosity was 200% of the original value. The permeability increased by up to 14 times. The tensile strength decreased significantly by up to 84%. The value of Young’s modulus of the rock decreased by up to 63.6%. The value of Poisson’s ratio was reduced by up to 40.7%. A combination of 6% HF + 15% HCl is recommended, with an effective acid treatment time of over 60 min for the Mahu conglomerate. Acidizing could significantly change the mechanical properties and permeability of the rock of the Mahu conglomerate reservoir, thus effectively reducing the formation fracturing pressure. This research provides technical support for Mahu acid dipping in horizontal well fracturing.

Effects of Fracture Parameters on VAPEX Performance: A Numerical and Experimental Approach Utilizing Reservoir-On-The-Chip

The present research carries out an in-detail study of the VAPEX process as one of the most recent solvent-based heavy oil recovery techniques in fractured reservoirs to evaluate the effect of fracture parameters on process performance. To achieve this purpose, several fractured patterns with distinct features were designed and engraved on glass pieces to manufacture state-of-the-art microfluidic models mimicking a typical Canadian heavy oil reservoir. A heavy oil sample of viscosity 1514 cP was utilized during the conducted experiments with pure propane and pure carbon dioxide as the injection solvents. A thorough image analysis operation was carried out over the experimental models to determine heavy oil produced, residual oil saturation, ultimate recovery factors, and monitor solvent chamber expansion. Numerical simulations of the same experiments were carried out for history matching and predicting other designed scenarios. Error analysis revealed average absolute errors of below 8%, showing convincing precision. Together with the simulation outcomes, a comprehensive data bank was obtained from the 30 scenarios designed and 18 VAPEX experiments conducted. The effects of fracture orientation, length, width, intensity, and position on process performance were identified and numerically evaluated. It was observed that all fractures, regardless of their properties, enhanced heavy oil recovery in comparison to the base case (no fractures) scenario. Moreover, propane proved more efficient owing primarily to its higher solubility and effective dispersion. The highest recovery factor, 65.81%, was obtained when implementing two wide vertical fractures on either side of the well pair. Almost equal to that, 64.93% was the process efficiency by positioning two long horizontal fractures between the wells.

Karst collapse and gypsum-filled veins in Eocene outcrops, Dammam Dome, Saudi Arabia: Causes and implications

• Differential weathering of Dammam Dome through uplift and erosion. • Factors affecting Dammam Dome geomorphology. • Gypsum-filled veins on the Dammam Dome due to karst collapse. • Results from this study can be related with water and hydrocarbon reservoirs. A recent road cut through Dammam Formation outcrop on the Dammam Dome in Dhahran, Saudi Arabia exposed an array of open fractures and gypsum-filled veins. The widespread array of fractures in the road cut was mostly contained within Saila Shale member and consisted of horizontal, vertical, and oblique extensional fractures, most were filled with gypsum. The gypsum veins are of varying thickness with the largest exceeding 2.5 inches. Vertical gypsum veins, similar to those encountered at the road cut, were found in adjacent areas. Thin layer of gypsum (about 1 inch) was also observed in the Rus Formation. The open fractures, in the Saila and Midra Shales members, were devoid of gypsum fill. Most of the open vertical and horizontal fractures were interpreted to be recent with indications of triggered by the excavation work. The open fractures and filled veins cover a stretch of about 250 ft. across the road cut that also exposed what was interpreted as a local karst collapse. Horizontally-layered and continuous rocks overlying the collapse indicated that it was a paleo structure. The causal mechanism for fracture formation and subsequent fill was associated with deformations accompanying post-karst collapse. Here, natural fracturing and fluid transport were not synchronous events. Insights from this interpretation offered an explanation for widespread surface structures with major and subtle morphologies on the Dammam Dome. These insights also highlighted the significance of collapse in the modification of the Dammam Dome over a geological timescale. The unstable nature of gypsum, prevalent in Dammam Formation in the Dammam Dome, has potential implications for integrity of anthropogenic structures such as roads and building foundations.

Reclassification and distribution patterns of discovered oils in the Dongying Depression, Bohai Bay Basin, China

The Dongying Depression is an important petrolifeous province, with diverse source rocks and complex petroleum distribution patterns. A total of 32 crude oils were analyzed by the gas chromatography–mass spectrometry and isotopic compositions to better understanding the petroleum systems in the study area. Three oil types were classified by hierarchical cluster analyses. Type I and II oils have closely correlation with the discovered source rocks, which have been confirmed to be mainly derived from the lower third and upper forth member of the Eocene Shahejie Formation source rocks (Es3L and Es4U), respectively. Obviously, type III oils contain abundant gammacerane, tricyclic terpanes and C29 steranes and have lower values of δ13C than type I and II oils, indicating a completely different source rock and biological origins. Until recently, type III oils fail to match any of the discovered source rock, which contains main contribution of aquatic organism or/and bacteria inputs. In addition, the spacial distribution of these three oil types were discussed. Type I oils mainly distributed in the Es3 and Es4 reservoirs that closed to the generative kitchens. Type II oils occurred in the Es4 reservoirs in the sourthern slope of the depression, which probably caused by lateral migration along the horizontal fractures and sandstone layers within the Es4 interval. Differently, type III oils in the sourthern slope of the depression were mainly discovered in the Eocene Kongdian or Ordocician reservoirs, which suggests great exploration potential of deep underlying strata.

A 75-year-old with left ankle pain.

A 75-year-old female with a history of smoking presented with left foot pain after a fall. She was cleaning her pool when she lost her footing while walking down a step. On extremity examination of her left ankle, there was plantar flexion weakness, a palpable dell at the insertion of the Achilles tendon, and a bony mass proximal to the gap (Figure 1). Left ankle radiographs were remarkable for an acute fracture of the posterior proximal aspect of the left calcaneus (Figure 2). Before surgery, the skin had become ecchymotic and edematous. The patient underwent open reduction with internal fixation with podiatric surgery. As there was enough bone remaining, 2 cannulated screws were placed to fix the fracture along with the attached Achilles tendon. The patient was discharged with a recommendation of non-weight-bearing status for the left lower extremity, a cast, and orthopedic follow-up in 2 weeks. Calcaneal fractures account for 1%–2% of all fractures. Calcaneal avulsion fractures account for less than 3% of calcaneal fractures.1 The calcaneus is the largest tarsal bone; it supports axial load from the body. This report demonstrates a type 2 calcaneal avulsion fracture; a “beak fracture” where the tendon pulls on the tuberosity causing a horizontal fracture.2 It also demonstrates a rare tongue-type fracture where the tuberosity splits into a superior and an inferior fragment.3 Patients often present with pain, swelling, and ecchymosis near the posterior aspect of the calcaneus. Patients can have skin tenting that can lead to skin necrosis if not treated.3 This woman had ecchymosis before surgery but did not have skin necrosis. It is important to assess these patients for neurovascular compromise and signs of other injuries. A plain radiograph is usually sufficient for diagnosis. Treatment depends on the severity. Fractures with skin tenting, neurovascular injury, or significant displacement will likely require open reduction and internal fixation in the operating room.4 This research was supported (in whole or in part) by HCA Healthcare and/or an HCA Healthcare affiliated entity. The views expressed in this publication represent those of the author(s) and do not necessarily represent the official views of HCA Healthcare or any of its affiliated entities.

Investigating the simultaneous fracture propagation from multiple perforation clusters in horizontal wells using 3D block discrete element method

Multi-cluster horizontal well fracturing is one of the key technologies to develop the unconventional reservoirs such as shales. However, the field data shows that some perforation clusters have little production contribution. In this study, a three-dimensional (3D) numerical model for simulating the multiple fracture propagation based on 3D block discrete element method was established, and this model considers the stress interference, perforation friction and fluid-mechanical coupling effect. In order to determine the most appropriate measures to improve the uniformity of multiple fracture propagation, the effect of the geologic and engineering parameters on the multiple fracture propagation in shale reservoirs is investigated. The modeling results show that the geometry of each fracture within a stage is different, and the outer fractures generally receive more fracturing fluid than the interior fractures. The vertical stress almost has no effect on the geometries of multiple fractures. However, higher horizontal stress difference, larger cluster spacing, smaller perforation number, higher injection rate, and smaller fracturing fluid viscosity are conducive to promote the uniform propagation of multiple fractures. The existence of bedding planes will increase the fluid filtration, resulting in a reduction in fracture length. The middle two fractures receive less fluid and the width of them is smaller. Through analyzing the numerical results, a large amount of fracturing fluid should be injected and the proppant with smaller size is suggested to be used to effectively prop the bedding planes. Cluster spacing and perforation number should be controlled in an appropriate range according to reservoir properties. Increasing the injection rate and reducing the viscosity of fracturing fluid are important means to improve the geometry of each fracture.

Experimental study on mechanical properties and fracture characteristics of shale layered samples with different mineral components under cyclic loading

In shale plays, the in-situ effective stress is continuously being perturbed because of the production which impacts field operations. Therefore, mechanical properties of the formation and its response to stress field changes, with respect to mineral variations, is of great significance for the proper design of horizontal drilling and hydraulic fracturing. In this paper, clay-rich, calcareous and siliceous black shales are classified based on their XRD analysis, from the Wufeng and Longmaxi Formations in the Sichuan Basin of the Upper Yangtze Plate. Uniaxial quasi-static and cyclic loading tests, acoustic emissions, and CT scanning are combined to study mechanical behavior and fracturing mechanisms of the shale layer samples that own different mineral components. The results show that the strength and deformation response of the samples is a function of their mineral composition. The damage from cyclic loading is gradually accumulated in the samples which ultimately leads to fatigue and sample failure. The compressive strength of the samples under cyclic loading is lower than in the uniaxial quasi-static conditions. Furthermore, the fracturing of rock under uniaxial quasi-static loading mainly occurs after the peak strength is achieved while in cyclic loading, when a certain stress level is reached, fracturing begins, the damage accumulates up to the peak stress and the rock suddenly fails. Based on CT images from the samples after rupture, failure modes of the clay-rich, calcareous and siliceous black shales mainly constitute extensional and shear fractures, with some conjugate shearing. In comparison with uniaxial quasi-static loading, the fracture volume of the clay-rich, calcareous and siliceous black shales after cyclic loading increases by 12.2%, 25.9% and 32.9%, respectively. Overall, this study explains how cyclic loading that can be applied in the field via changing the injection pressure and other stimulation parameters, can effectively improve the complexity of the shale fracture network and lead to higher productivity of the formation.

Optimization of volume fracturing technology for shallow bow horizontal well in a tight sandstone oil reservoir

The physical property of Chang 6 reservoir in Yanchang oilfield is poor, and the heterogeneity is strong. Multistage fracturing of horizontal wells is easy to form only one large horizontal fracture, but it is difficult to control the fracture height and length. The new mining method of “bow horizontal well + multistage horizontal joint” can effectively increase the multistage horizontal joint’s spatial position, which improves the drainage area and stimulation efficiency of oil wells. Due to the reservoir’s low permeability and strong heterogeneity, the single well mode of “bow horizontal well + multistage horizontal fracture” cannot effectively produce Chang 6 reservoir. To improve the production degree of the g 6 reservoir, the fracture model is established using equivalent conductivity and the multigrid method. The pressure response functions of horizontal wells and volume fracturing horizontal wells are established by using the source function, and the relationship between reservoir permeability and starting pressure gradient in the block is calculated. On this basis, the reservoir productivity equation of the block is established, which provides a basis for optimizing the fracturing design parameters of horizontal wells. It is proposed that the flow unit should be considered in the design of fracturing parameters of horizontal fractures, the number of fractures should comprehensively consider whether the fractures can make each flow unit be used, and have large controlled reserves, and the scale of fracturing should comprehensively consider the output and cost. The fracture network model is established by using equivalent conductivity and multi-gridthod, and the volume fracturing design parameters of horizontal wells are optimized, considering the seepage characteristics of the flow unit. The fracturing design parameters of the horizontal section are further defined, which provides a theoretical basis for the efficient development of shallow tight reservoirs.

The influence of roof lithology on the fracture propagation of horizontal well multistage fracturing in the roof of broken soft coal seams

Horizontal well multistage fracturing in the roof of broken soft coal seams has been demonstrated to be an effective technique to extract coalbed methane (CBM). However, fracture propagation behaviours under this technology vary significantly with different roof lithologies. Therefore, the influence of roof lithology on fracture propagation was investigated in this study. Based on the No. 5 and No. 11 coal seams in the Hancheng block of the Ordos Basin in China, field tests of horizontal well multistage fracturing in the sandstone and mudstone roof of crushed soft coal seams were performed and fractures were detected by microseismic monitoring. Corresponding hydraulic fracturing physical simulation experiments were conducted. The results show that the effectively propped fractures in the roof can provide flow channels for CBM. The better microseismic monitoring fractures and higher CBM production than direct fracturing in coal seams demonstrated the desirable feasibility of this technology. For the sandstone roof, the morphologies of hydraulic fractures were regular and one main fracture was formed by each perforation cluster. For the mudstone roof, the shapes of fractures were irregular and complicated fracture networks were formed. The findings can improve the design of horizontal well multistage fracturing in the roof of broken soft coal seams.

Fracture prediction of tight sandstone reservoirs using outcrops and log curve-based extremum method: A case study of the Chang 7 Member of the Yanchang Formation in Block X, Ordos Basin

The lack of seismic data and special log data on the Chang 7 Member of the Yanchang Formation in Block X of the Ordos Basin poses a major challenge to the study of the development characteristics and identification of fractures that greatly influence on-site production. To overcome this obstacle, this study determined the macroscopic characteristics of fractures in the study area based on field outcrop profiles and indoor core observations. The results are as follows: (1) Fractures in the study area are dominated by regional fractures in weakly deformed structural areas, with three sets of fractures mainly occurring. Core observations show that fractures in the study area have high dip angles, small extensions, and small openings; (2) The vertical extended lengths of these fractures are significantly controlled by rock mechanical layers; (3) Fractures show three types of extended morphologies when meeting weak planes. Vertically, there is an exponential correlation between the sand body thickness and the fracture linear density. The argillaceous shale thickness has a logarithmic relationship to the fracture linear density when it is < 1 m and has an exponential relationship to the latter otherwise. The planar distribution of fractures is significantly affected by layer thickness and rock mechanical properties. Given the stable occurrence, high dip angles, and small extensions of regional fractures, this study highlighted the abnormal increase or decrease in log curve values of fracture segments by calculating the extrema of log curves. The purpose is to identify the locations and quantity of fractures using conventional log curves in the case of limited drilling data. This log curve-based extremum method enjoys a high resolution. For both coring and non-coring wells in the study area, there is a positive correlation between their fracture linear density determined based on the production segment thickness of vertical wells and their daily liquid yield in the first week of well test and pilot production. This result indicates that the method for identifying natural fractures proposed in this study is highly reliable. Moreover, this study provides key parameter controls for predicting the three-dimensional distribution of fractures. The understanding of the fracture spatial distribution is also a key external factor that affects the design and construction of horizontal well fracturing.

Numerical Simulation of Two-Phase Flow in Glutenite Reservoirs for Optimized Deployment in Horizontal Wells

It is known that the pore media characteristics of glutenite reservoirs are different from those of conventional sandstone reservoirs. Low reservoir permeability and naturally developed microfractures make water injection in this kind of reservoir very difficult. In this study, new exploitation methods are explored. Using a real glutenite reservoir as a basis, a three-dimensional fine geological model is elaborated. Then, combining the model with reservoir performance information, and through a historical fitting analysis, the saturation abundance distribution of remaining oil in the reservoir is determined. It is shown that, using this information, predictions can be made about whether the considered reservoir is suitable for horizontal well fracturing or not. The direction, well length, well spacing and productivity of horizontal well are also obtained.

Study on effects of highly deviated well on thin interbedded reservoirs fracturing

Highly deviated well is widely applied in thin interbedded reservoirs fracturing in changqing oilfield. the oil production data shows that highly deviated fracturing well can increase the oil production compared with horizontal well fracturing, which suggests that highly deviated well fracturing is more efficient. However, it still needs deeper understanding for the mechanism of highly deviated well increase oil production, to study this problem, True-axial hydraulic fracturing physical simulation test is carried out on two kinds of cement specimen with interlayers, the results show that cement specimen for highly deviated well is more productive because fractures are more likely to cross the interbedded layers and connect oil reservoirs that separated by interlayers. Further research on the mechanism of highly deviated well fracture crossing interbedded layers is conducted via numerical simulation. Cohesive zone model is adopted to simulate the propagation of fracture in highly deviated well and horizontal well to compare the difference of thin interbedded layers stress. the results show that due to the deflection of highly deviated well fracture during propagation, the reservoir mass is divided into two parts, which causes relative displacement of rock mass on both sides of the fracture under the effect of vertical principal stress, thin interlayer eventually got broken under the action of tensile and shear stress. Both laboratory tests and numerical simulation results show that highly deviated wells have stronger interlayer penetration capability, which can improve the fracturing effect of thin interbedded reservoirs.

Stress Characteristics near Wellbore and Prevention Casing Deformation for Fracturing Horizontal Wells

Aiming at the problem that casing deformation can easily occur in tight oil horizontal well fracturing, based on the rock mechanics experiments and probability statistics, the distribution characteristics and law of the near-wellbore stress field of the reservoir in STH M56 were solved and analyzed by using the finite element modeling numerical method. The research shows that (1) the max/min horizontal stress ratio of the M56 tight oil reservoir is 1.2, the difference is less than 8 MPa, and this characteristic condition is more conducive to the formation of complex fracturing network in the reservoir during fracturing. (2) In M56, the Mises stress isoline near the borehole is symmetrically distributed. Stress concentration has four dangerous points (30°, 150°, 210° and 330°); a sector-shaped high dangerous stress zone is formed along the four dangerous points. As the pumping pressure increases, the vertical Mises stress first increases and then decreases, while the horizontal Mises stress first decreases and then increases. The max-Mises stress at the casing wall is linearly and positively correlated with the stress uniformity coefficient. When the pumping pressure is 80 MPa, the Mises stress exceeds the safe pressure limit of the casing. A pumping pressure of 70 MPa fracturing is the safe pumping pressure for the reservoir casing. (3) It is found that the 90° and 270° horizontal fixed plane perforations can avoid the dangerous stress zone, increasing and decreasing the injection flow rate of the fracturing pump step by step ( step pressure ≤ 5 MPa ) at the start and stop stages of fracturing; the control of the pump pressure during the whole process of fracturing is within 70 MPa, which can prevent the casing deformation.

Influence of Fracture Geometric Characteristics on Fractured Rock Slope Stability

Analysis of the stability of slopes in fractured rock masses is not trivial and is fraught with uncertainty and risk. A DFN-DEC model (Discrete Fracture Network-Distinct Element Code) based on the MATLAB platform is developed to evaluate the stability of rock slopes with random fractures. Then, the influences of mean values of geometric characteristics (i.e., the trace length T, the dip D, and the spacing S) for both the horizontal (denoted with 1) and inclined (denoted with 2) fractures on the mean slope stability are investigated. The results indicate that the proposed DFN-DEC model based on the MATLAB platform is adequate, robust, and can generate more realistic fracture networks. By means of probabilistic analysis (i.e., Monte Carlo simulation), we can obtain a more accurate stability assessment result of fractured rock slopes. In addition, it is found that the μFs (the mean of Fs) of slopes decreases with the increase in μT1, μT2 (the mean trace length of horizontal and inclined fractures, respectively) and μD1 (the mean dip of horizontal fractures), and increases gradually with the increase in μD2 (the mean dip of inclined fractures), μS1 and μS2 (the mean spacing of horizontal and inclined fractures, respectively). Furthermore, the geometric characteristics related to inclined fractures have a much greater influence on μFS than that related to horizontal fractures. This study can be well applied in engineering practice, e.g., preliminary evaluation of the slope stability according to the statistics of fracture geometric characteristics.

Using discrete element numerical simulation to determine effect of persistent fracture morphology on permeability stress sensitivity

AbstractThe stress sensitivity of coal seams with different fracture structures affects gas migration characteristics in the fracture zone. In this study, permeability stress experiments for intact and persistent fracture coal samples are carried out. A discrete element method numerical simulation that adopts the changing joint stiffness method is proposed. Based on the experimental data, the corresponding parameters of persistent fractures and elastic joints for fluid–solid coupling simulations are determined. Subsequently, the internal influence mechanisms of fracture morphology on axial and confining stress sensitivities are determined. The simulation results show that sectional fractures with different dip angles in the persistent fracture control the sensitivity to axial and confining stresses. The horizontal segment fracture aperture decreases with an increase in axial stress, which reduces its flow capacity. This results in a decrease in the flow rates in the persistent fracture. When the confining stress increases, the vertical fracture aperture is significantly reduced, considerably reducing the flow rate in the persistent fracture.

A control method for hydraulic fracturing of the hard roof with long and short boreholes

During the mining of the working face, the hard roof can lead to a series of problems, such as air leakage in goafs, gas emission and concentration, casualties, and damages to buildings and ecological environment. The treatment of the hard roof has always been a difficult problem in major coal-producing countries. Although many scholars have conducted some theoretical research and field practice in this field in recent years, the aforementioned safety problems still occur frequently. In order to understand the mechanism of crack propagation caused by hydraulic fracturing of the roof, based on the theoretical analysis of linear elastic fracture mechanics and coal rock mechanics, the shear fracture criterion was determined for the formation of horizontal fractures in the natural cracks. The anisotropy of the crack tip, the adhesion forces in the coal and rock fracture surface and the conditions for hydraulic-induced crack propagation were also considered. The formation of cracks involves a vertical main crack and multiple extended-airfoil branch cracks which interconnect transversely and longitudinally. Under the effect of hydrodynamic water wetting and hydraulic fracturing, the stress of coal and mass changed. Meanwhile, the mechanical parameeters, such as compression, tensile strength and elasticity modulus and etc., were weakened, thus achieving the goal of structural transformation and slight weakening of coal and rock mass. According to the bidirectional stress of coal and rock mass, the maximum principal compressive stress of crack opening was calculated, and the propagation mechanism of hydraulic fracturing cracks in the hard roof was obtained. The hydraulic fracturing technology for controlling the hard roof was illustrated and has been applied in No. 2 Well of Sihe Coal Mine for many years. The research results could provide reference for the control of the hard roof in other similar mines.

Conductivity Evaluation of Horizontal Wells in Coalbed Methane Reservoirs: Applicability of Micromaterial Tracer Testing Technology.

Horizontal well-staged fracturing technology is widely used in the exploitation of coalbed methane reservoirs. Most coalbed methane wells have little or no flowback fluid after fracturing due to strong adsorption in the reservoir. The fracture conductivity of each fracturing interval can only be evaluated in the water drainage and gas production stage. Traditional chemical tracer monitoring technologies are risky to operate and do not provide accurate qualitative measurements. The potential applicability of trace material tracer testing technology in coalbed methane reservoirs has theoretical and practical significance, as does establishing a set of fracturing tracer technologies (e.g., reagent systems, construction schemes, detection interpretation) suitable for coalbed methane horizontal wells. Geological, laboratory, and field test data are used in this study to preliminarily resolve the trace material tracer adsorption problem in the coalbed by improving the chemical agent formula. The proposed method is applied to determine the conductivity of a fractured section in a coalbed methane well.