Horizontal Shale Gas Research Articles

Integrated numerical simulation of hydraulic fracturing and production in shale gas well considering gas-water two-phase flow

Based on the displacement discontinuity method and the discrete fracture unified pipe network model, a sequential iterative numerical method was used to build a fracturing-production integrated numerical model of shale gas well considering the two-phase flow of gas and water. The model accounts for the influence of natural fractures and matrix properties on the fracturing process and directly applies post-fracturing formation pressure and water saturation distribution to subsequent well shut-in and production simulation, allowing for a more accurate fracturing-production integrated simulation. The results show that the reservoir physical properties have great impacts on fracture propagation, and the reasonable prediction of formation pressure and reservoir fluid distribution after the fracturing is critical to accurately predict the gas and fluid production of the shale gas wells. Compared with the conventional method, the proposed model can more accurately simulate the water and gas production by considering the impact of fracturing on both matrix pressure and water saturation. The established model is applied to the integrated fracturing-production simulation of practical horizontal shale gas wells. The simulation results are in good agreement with the practical production data, thus verifying the accuracy of the model.

Measurement method of gas holdup in horizontal gas-liquid two-phase flow based on fiber-optic probe array

Aiming at the problem of gas holdup measurement in horizontal shale gas wells with low flow rates, a fiber-optic probe array sensor for horizontal gas-liquid stratified flow is designed and developed. The Fluent fluid volume method is used to establish a simulation model of gas-liquid two-phase flow in the horizontal collecting pipe, and a study on the flow characteristics and flow patterns in the gas-liquid two-phase flow in the horizontal collecting pipe with low gas flow is carried out. Based on the acquisition of the fluid flow pattern is stratified flow characteristics, the design of the fiber-optic probe array structure with different numbers and positions of the probes, and the fiber-optic probe array sensor is modeled using the ZEMAX ray tracing software, simulation analysis of its response characteristics in different flow patterns and the array structure selection. Finally, based on the above research, the fiber-optic probe array sensor for gas holdup measurement is designed and developed, and the platform for gas-liquid two-phase flow is constructed and experimentally verified. The experimental results show that the developed fiber-optic probe array sensor has good applicability for gas holdup measurement under stratified flow, and the error of the measurement does not exceed 0.1.

Analysis of uneven density of oil-based drilling fluid caused by shale respiration

Longmaxi shale formation has developed beddings and fractures in southern Sichuan, which is prone to well leakage and wellbore instability. In the drilling process of horizontal section of Ning 209H58-2 well, drilling fluid would loss during circulation and return after pump stopped in the same section, which was the obviously respiration effect. The larger amount of leakage and pumping back, the greater the difference of drilling fluid density would be, accompanied by the increasing value of the gas. In this paper, shale was determined to have “screen effect” by assuming methods, the drilling fluid would loss as the equivalent circulating density was greater than the crack opening pressure, and the crack width was just in the size range of barite particle, then the larger size barite cannot enter in shale cracks end gathered together, and low density drilling fluid would penetrated into the formation, and then the drilling fluid density would be high in the first and low then after circulation again. The equivalent circulating density would be controlled by reducing the drilling fluid density, the effects of microfracture opening and respiration would be avoided, and the drilling fluid density would return to normal after circulation. This paper illustrates that the shale screen effect was the main reason for the uneven density of drilling fluid, which was expected to provide technical support for the development of horizontal shale gas Wells.

Experimental Water Activity Suppression and Numerical Simulation of Shale Pore Blocking

The nanoscale pores in shale oil and gas are often filled with external nanomaterials to enhance wellbore stability and improve energy production. And there has been considerable research on discrete element blocking models and simulations related to nanoparticles. In this paper, the pressure transmission experimental platform is used to systematically study the influence law of different water activity salt solutions on shale permeability and borehole stability. In addition, the force model of the particles in the pore space is reconstructed to study the blocking law of the particle parameters and fluid physical properties on the shale pore space based on the discrete element hydrodynamic model. However, the migration and sealing patterns of nanomaterials in shale pores are unknown, as are the effects of changes in particle parameters on nanoscale sealing. The results show that: (1) The salt solution adopts a formate system, and the salt solution is most capable of blocking the pressure transmission in the shale pores when the water activity is 0.092. The drilling fluid does not easily penetrate into the shale pore space, and it is more capable of maintaining the stability of the shale wellbore. (2) For the physical blocking numerical simulation, the nanoparticle concentration is the most critical factor affecting the shale pore blocking efficiency. Particle size has a large impact on the blocking efficiency of shale pores. The particle diameter increases by 30% and the pore-blocking efficiency increases by 13% when the maximum particle size is smaller than the pore exit. (3) Particle density has a small effect on the final sealing effect of pore space. The pore-plugging efficiency is only increased by 4% as the particle density is increased by 60%. (4) Fluid viscosity has a significant effect on shale pore plugging. The increase in viscosity at a nanoparticle concentration of 1 wt% significantly improves the sealing effectiveness, specifically, the sealing efficiency of the 5 mPa-s nanoparticle solution is 16% higher than that of the 1 mPa-s nanoparticle solution. Finally, we present a technical basis for the selection of a water-based drilling fluid system for long horizontal shale gas drilling.

Investigation on the interlayer intercalation inhibition mechanism of polyamines with different adsorption functional groups on montmorillonite: Experiment and density functional theory simulation

Water-based drilling fluids (WBDFs) are gaining popularity as they exhibit comparable inhibitory properties to oil-based drilling fluids, making them an ideal choice for drilling horizontal shale gas wells. This study focuses on understanding the intercalation inhibition mechanism of various inhibitors, namely 1,6-hexane diamine (HDA), N,N′-dimethyl-1,6-hexane diamine (DHDA), N,N,N′,N′-tetramethyl-1,6-hexane diamine (THDA), and hexamethyl diammonium chloride (HDC), each possessing different functional groups. The interaction and performance of these inhibitors on the swelling of montmorillonite (Mt) were investigated through a combination of experimental techniques containing X-ray diffraction, thermogravimetric analysis, X-ray photoelectron spectroscopy, transmission electron microscopy, scanning electron microscopy, and density functional theory simulation. Results reveal that at a low dosage of 0.7 CEC (cation exchange capacity), the wet Mt-HAD, Mt-DHDA, Mt-THDA, and Mt-HDC compounds exhibit basal spacing of 1.30 nm, 1.33 nm, 1.34 nm, and 1.42 nm, respectively. The basal spacing remains unchanged when a higher dosage of 3.0 CEC is added. Comparatively, the basal spacing of dry Mt-inhibitor compounds is slightly reduced. This suggests that the addition of a smaller amount of inhibitor also demonstrates excellent inhibitory performance. Thermogravimetric and differential thermogravimetric analysis of Mt-inhibitor hybrid structure indicate that Mt-HDA compounds exhibit both low and high-temperature peaks, while Mt-DHDA, Mt-THDA, and Mt-HDC compounds only show a low-temperature peak. This indicates that while HDA partially inhibits surface hydration of Mt, DHDA, THDA, and HDC effectively inhibits surface hydration of Mt. Additionally, the microscopic mechanism of inhibitor adsorption on the Mt was explored using density functional theory simulation. HDC adsorption energy on Mt significantly increased relative to DHDA, THDA, and HDA. This indicates that inhibitors featuring quaternary ammonium functional groups exhibited superior inhibitory performance. As a result, inhibitors with quaternary ammonium functional groups hold promise as potential shale inhibitors for WBDFs.

Simulation and optimization of fracture pattern in temporary plugging fracturing of horizontal shale gas wells

Horizontal well-staged fracturing is a key technology for efficient shale gas production. However, stress shadows between clusters make it difficult to synchronize the initiation and expansion of hydraulic fractures in multi-cluster fracturing. Mine practice has shown that the use of temporary plugging fracturing can promote the balanced expansion of the multi-fractures. This study establishes a numerical model for fracture-opening temporary plugging fracturing based on the three-dimensional discrete lattice method. Then, the impacts of perforation cluster spacing, stress difference, temporary plugging timing, amount of temporary plugging balls (TPBs), and temporary plugging times on the expansion pattern of multi-fractures were simulated. Additionally, the effectiveness of temporary plugging was further verified by laboratory experiments and mine site experiments. The result shows that, decreasing the cluster spacing can significantly increase the extension range of hydraulic fractures, but the uneven propagation of fractures is severe. Meanwhile, the fracture volume differentiation coefficient gradually increased with the increase of the stress difference. When the temporary plugging timing is 2/3 of the overall fracturing duration, the fracture clusters expand evenly and the fracture volume differentiation coefficient reaches the minimum value. Moreover, as the quantity of TPBs increases, the fracture volume differentiation coefficient first decreases and then increases. Finally, to increase the effectiveness of temporary plugging fracturing, the times of temporary plugging should be minimized. The results of this research can help optimize temporary plugging fracturing in shale gas reservoirs.

Effect of Lateral Trajectory on Two-Phase Flow in Horizontal Shale Gas Wells

Horizontal gas wells are one of the key technologies for the production of shale gas reservoirs. Compared with conventional gas reservoirs, horizontal shale gas wells have ultra-long and complex lateral sections. Overall, toe-up, toe-down, and horizontal trajectories will be exhibited in the lateral section. The statistical results of field production data indicate that the lateral trajectory has a significant impact on the estimated ultimate recovery. However, the mechanism has not yet been fully revealed owing to the complicated two-phase flow in lateral pipes. Therefore, taking horizontal shale gas wells’ lateral section as the research object, we designed our experimental parameter ranges based on horizontal shale gas wells in the Changning shale gas field. Simulation experimental tests were conducted on the pipe with an inclined angle from −15° to 15° to analyze the effects of different gas velocities, liquid velocities, and pipe inclinations on flow patterns and liquid holdup. Based on our observations and measurements, we evaluated the flow pattern prediction methods and drew a new flow pattern map for pipes with an inclined angle from −15° to 15°. Based on the momentum conservations between the gas and liquid phases and measured liquid holdup data, a new liquid holdup model was established in the pipes with inclined angle from −15° to 15°. Experimental and field-measured data were collected to verify the new method’s accuracy.

Effect of Matrix Permeability on a Horizontal Shale Gas Well Performance using a Fully Coupled Fluid Flow with Geomechanics Model

Recently, hydrocarbon production from unconventional oil and gas resources has emerged. The most common unconventional oil and gas resources are found in shale formations. These shale formations are well-known for being stress-sensitive. Usually, traditional tools are used to model and study production from such formations. However, conventional modeling techniques denote rock deformation using constant rock compressibility. Such an approach is useful for studying conventional hydrocarbon resources where formation stress sensitivity is insignificant. However, when it comes to modeling stress-sensitive formations such as shale formations, it is important to include the rock deformation and its effects on the overall fluid flow in porous media. To consider the rock deformation in the fluid flow model, the coupling of fluid flow with the geomechanics model has to be used. This study utilizes a fully coupled fluid flow with a geomechanics model. In addition, shale formations are also known to have an ultra-low matrix permeability, and production usually results from hydraulic fractures that act as flow conduits. Consequently, the effect of matrix permeability on hydrocarbon production is rarely studied. This study focuses on the effect of matrix permeability on the production performance of a single horizontal well in Barnett Shale. It also focuses on the effect of matrix permeability on production performance when the geomechanics effects are coupled with the fluid flow model and decoupled. The results show that the higher the matrix permeability, the better the production performance of the well. The results also show that the higher the matrix permeability, the higher the estimated cumulative production difference between the two models (when the geomechanics effects are coupled and decoupled).

Quantifying the Widths of Fault Damage Zones Based on the Fault Likelihood: A Case Study of Faults in the Fuji Syncline of the Luzhou Block, Sichuan Basin, China

Faults are critical to the preservation or destruction of shale gas concentration. The Lower Silurian Longmaxi Formation in the southern Sichuan Basin hosts relatively developed faults, which pose a huge challenge to the exploration and exploitation of shale gas. An urgent need to quickly determine the widths of fault damage zones (FDZs) arises in locating horizontal shale gas wells. In this study, FDZs were estimated using the fault likelihood. The results are as follows: (1) It is rational to constrain the FDZ width using a fault likelihood greater than 0.2. The six major NEE-trending faults in the Fuji syncline of the Luzhou block have complex structures and varying FDZ widths from about 240–1220 m. (2) The degree of influence of FDZs is negatively correlated with their distance from the faults. In other words, a greater distance from a fault is associated with a weaker influence and a smaller fault likelihood. (3) Based on the ratio of the fault throw to the FDZ width, we propose that the width of seismic-scale fault damages can be directly constrained using a ratio value of 3.5. This method is fast and accurate and can provide support for the evaluation of the shale gas preservation conditions and well placement in the Longmaxi Formation of the southern Sichuan Basin.

Research on Cuttings Carrying Principle of New Aluminum Alloy Drill Pipe and Numerical Simulation Analysis

In order to improve the cuttings transport ability and well hole purification effect of horizontal shale gas wells in the Sichuan and Chongqing area, a new type of aluminum alloy drill pipe is put forward, and the floatability is validated by theoretical analysis and actual parameter calculation. According to the cuttings migration mechanism, the cuttings cleaning simulation model of the new aluminum alloy drill pipe and the traditional steel drill pipe was established by Fluent, and the hexahedral mesh is used to divide the model. Thus, the mesh independence and convergence of the two models are verified. Then, the simulation model is verified by comparing the calculation results of the two simulation models with the experimental data of the indoor cuttings migration device. Finally, the rock-cleaning ability of the two drill pipes is analyzed under the conditions of changing the cuttings particle size, well inclination angle, displacement, and mechanical speed. Compared with the traditional steel drill pipe, the new aluminum alloy drill pipe can improve the borehole purification capacity by 13% on average. This research result is of great significance in reducing the quality of cuttings in the annulus and improving the borehole purification effect.

A Study on the Production Performance of a Horizontal Shale Gas Well Using a Fully Coupled Flow and Geomechanics Modeling

Conventional petroleum reservoir simulators use constant rock compressibility to denote rock deformation. However, due to the stress-sensitive nature of the shale formations, using constant rock compressibility in reservoir simulators does not accurately capture the pressure diffusion in the reservoir, leading to a higher error margin in flow rate estimation. Fluid flow coupling with geomechanics is used to account for such a phenomenon numerically. Such an approach is important for shale numerical studies and any energy underground storage modeling (i.e., CO2 storage). Usually, when fluid flow coupling with geomechanics is studied for shale formations, the fluid, and the stimulated reservoir petrophysical properties are overlooked. This paper aims to present a study on the effect of the fluid and reservoir petrophysical properties on the performance of a gas-producing well. In addition, the results from the cases when geomechanics is coupled and decoupled with fluid flow in reservoir simulations are compared. The governing equations were discretized using the Finite Element Method. First, the model was validated against Terzaghi's consolidation theory analytical solution. After that, a history matching for the production flow rate was performed using field production data from Barnett Shale. Then a sensitivity analysis was carried out for the gas viscosity, Stimulated Reservoir Volume (SRV) porosity, and fracture conductivity. Next, the sensitivity analysis was conducted for the coupled and decoupled cases. Finally, the sensitivity analysis results were compared between the coupled and decoupled cases. The results show that lower gas viscosity, higher SRV porosity, and higher fracture conductivity improved horizontal well production performance. In addition, when the geomechanical effects were decoupled, the reservoir simulator overestimated the production flow rate and cumulative production.

Evaluation of the fracturing fluid flowback based on perforation clusters for horizontal shale gas wells using data-mining methods

Multi-stage hydraulic fracturing is a crucial technique in the development of horizontal shale gas wells. After fracturing and shut-in for several days, the well would be opened and the fracturing fluid injected into the gas formation would flow back to the ground along with extracted gas. Field experts suggest fracturing fluid flowback plays a key role in the production of shale gas and hope to find the relationship between flowback and production. However, the flowback and production data we collected from 161 wells in one shale gas field in China illustrate that there is no general relationship between flowback and production. The main reason we deduce is that the commonly-used cumulative flowback amount is not a good indicator to represent shale gas wells’ flowback situation. Therefore, we propose a new flowback indicator based on filed data and a shale gas flow model. The proposed indicator is the cumulative flowback ratio per fracturing cluster calculated on production days, where production day is a newly proposed time measurement substituting the calendar day. Further study illustrates that the proposed indicator can be easily predicted using a random forest model with engineering parameters, geological parameters, and well operation parameters. Besides, fracturing scale parameters and brittle mineral proportion are identified as the most important controlling factors of the proposed indicator. With the help of the newly proposed flowback indicator, field experts can have a new way to comprehend each well’s flowback characteristics and make better development plans.

Study on Fault Activation Evaluation Mechanism and Sensitivity Analysis in Shale Gas Hydraulic Fracturing

Shale gas hydraulic fracturing usually activates nearby faults and makes them slip. In horizontal wells, fault slip can result in serious casing deformation. Casing deformation slows the fracturing process, lowers production, and raises the cost of a shale gas well. It is challenging to obtain underground data on fault activation because of the deep shale reservoirs. As a result, the current study needed to indicate how hydraulic fracturing affects fault activation length. This made it challenging to control casing deformation. The fluid-structure coupled finite element method was used in this study to create a coupled seepage-stress model for heterogeneous shale formation. With microseismic signs and hydraulic fracking for shale gas, this model examined the variation law of pore pressure and ground stress. The fault activation coefficient was created to assess the fault activation duration and the impact of hydraulic fracturing. The model was verified by the microseismic signal. The outcomes of the numerical simulation demonstrate how the rapid rise in formation pore pressure during hydraulic fracturing affected the ground stress at the fault interface. The influence of ground stress variation at the fault interface on fault activation could not be ignored. Increased fault elastic modulus, fracture pressure, fracture time, and the fault Poisson ratio result in longer fault activation lengths. The length of the fault’s activation was decreased by the increase in fracture stage, distance from the fault, friction angle within the fault, and fault angle. Finally, a shale gas horizontal well with casing deformation in block C was analyzed. The results showed that reducing the fracturing duration can reduce the activation length of the fault by 68.25%, resulting in a 9.1 mm fault slide and a 0.86 mm casing deformation, respectively. This study offers theoretical guidelines for preventing fault activation during hydraulic fracturing in horizontal shale gas wells.

Factors affecting casing equivalent stress in multi-cluster fracturing of horizontal shale gas wells: finite element study on Weirong Block, southern Sichuan Basin, China

Multi-cluster fracturing technology was often used in horizontal well reservoir reconstruction to achieve production increase, which also affected casing equivalent stress distribution. This paper focuses on multi-cluster fracturing and establishes a fracturing model in line with the reality. The three-dimensional finite element model of multi-cluster fracture-formation-cement sheath-casing was proposed, the influence of cluster spacing and fracturing cluster number on casing equivalent stress was studied. On this basis, a single segment 8-cluster three-dimensional finite element model was developed. The influence of rock elastic modulus, casing inner wall pressure, geostress change and elastic modulus of cement sheath on casing equivalent stress was simulated from two aspects of uniform and non-uniform extrusion of wellbore. Actual data was used and analyzed for the fracturing section of a well in Weirong Block, southern Sichuan Basin, China. The results showed that the casing equivalent stress decreased with the increase of fracture dip angle. The casing equivalent stress increased with the increase of cluster spacing; however, it decreased with the increase of rock elastic modulus. The casing equivalent stress increased with the increase of casing wall pressure. Also, the cracks extrude the casing evenly did not affect the change on casing equivalent stress. It was also found that, when casing was uniformly squeezed by multiple fractures, the difference of ground stress had little effect on casing equivalent stress, while non-uniform extrusion had greater effect on casing equivalent stress. Further, when there was no wellhead pumping pressure, the casing equivalent stress increased with the increase of the elastic modulus of the cement sheath, and decreased on the contrary. The elastic modulus of rock was lower than that of cement sheath, and the casing equivalent stress increased with the increase of the elastic modulus of cement sheath, and decreased on the contrary. The research results had certain guiding significance for the prevention and control of casing damage in fracturing section.

A Combined Gated Recurrent Unit and Multi-Layer Perception Neural Network Model for Predicting Shale Gas Production

Shale gas plays an important role in supplementing energy demand and reducing carbon footprint. A precise and effective prediction of shale gas production is important for optimizing completion parameters. This paper established a gated recurrent unit and multilayer perceptron combined neural network (GRU-MLP model) to forecast multistage fractured horizontal shale gas well production. A nondominated sorting genetic algorithm II (NSGA II) was introduced into the model to enable its automatic architectural optimization. In addition, embedded discrete fracture models (EDFM) and a reservoir simulator were used to generate training datasets. Meanwhile, a sensitivity analysis was carried out to find the variable’s importance and support the history matching. The results illustrated that the GRU-MLP model can precisely and efficiently predict the productivity of multistage fractured horizontal shale gas in a rapid and effective manner. Additionally, the model fits better at peak values of shale gas production. The GRU-MLP hybrid model has a higher accuracy within an acceptable computational time range compared to recurrent neural networks (RNN), long short-term memory (LSTM), and GRU models. The mean absolute percentage error (MAPE) and root mean square percentage error (RMSPE) for shale gas production generated by GRU-MLP model were 3.90% and 3.93%, respectively, values 84.87% and 84.88% smaller than those of the GRU model. Consequently, compared with a purely data-driven method, the physics-constrained data-driven method behaved better. The main results of the study will hopefully contribute to the intelligent development of shale gas production prediction.

Tubing Depth Optimization Study of Horizontal Well Drainage and Gas Production in WeiYuan Shale Gas Field

Timely production with a tube in shale gas wells can effectively ensure the stable decline of gas wells. However, there is no in-depth study on which position of tubing is the most favorable for the stable production of gas wells and whether the wellbore trajectory has an impact on this position. To determine the reasonable end of tubing (EOT), firstly, through the gas water flow experiment of the whole wellbore test device of a horizontal well, the characteristics of liquid accumulation in the test section and the liquid discharge at the outlet are analyzed. The results show, when the horizontal section inclines upward and the end of the tubing reaches 1/3 of the horizontal section, the gas flow carrying liquid is the smallest. Then, OLGA software is used to simulate the wellbore effusion in the production process of gas wells with different tubing depths under different wellbore trajectories. The results show when the horizontal section inclines upward and the end of the tubing arrives at 1/3 of the horizontal section, the cumulative production of the gas well is the largest. Based on comprehensive analysis, it is most favorable for horizontal shale gas wells when the end of the tubing is about 1/3 of the horizontal section.

An Artificial Intelligence Algorithm for the Real-Time Early Detection of Sticking Phenomena in Horizontal Shale Gas Wells

An Artificial Intelligence Algorithm for the Real-Time Early Detection of Sticking Phenomena in Horizontal Shale Gas Wells

Effect of Fault Slip on the Casing Passability of Horizontal Shale Oil and Gas Wells

Summary Fault slip, a secondary effect of the hydrofracture to extract shale oil and gas, deforms the casing locally and affects downhole tools going through it, hindering the exploitation plan. The casing passability is introduced to evaluate the casing passability for the downhole tool. A simulation model of the fault slip was established to analyze the effect of fault type, slip distance, and fault dip on the casing passability. Meanwhile, the simulation method adopted in this paper was verified by the large-scale physical experiments of the perforated casing subjected to uniform outer pressure. Based on the experimental results and the geometry of fault slip, an empirical formula is proposed for the relationship between casing passability and fault slip. The result shows that the sensitivity of casing passability affected by fault type is ranked from highest to lowest by strike-slip fault, normal fault, and reverse fault. This study provides a reference for determining the available diameter of downhole tools quickly and reduces the cost of exploring wells when downhole tools are obstructed.

Hydraulic fractures simulation in non-uniform stress field of horizontal shale gas well

Shale reservoirs have low porosity and ultra-low permeability. A significant increase in gas well production requires horizontal well fracturing. In this view, the propagation behavior of hydraulic fractures during the fracturing process is critical to the effect of shale gas reservoir stimulation. However, some shale formations have developed faults and the in-situ stress field has a non-uniform distribution. Also, the maximum horizontal principal stress direction varies with the spatial position, and non-planar deflection propagation behavior in hydraulic fractures is possible. The purpose of this article is to reveal the effect of the development of faults in the shale formation on the propagation of hydraulic fractures. A calculation model for the non-uniform tectonic stress field near the fault was established, and on this basis, we constructed a shale gas horizontal well-staged multi-cluster fracturing hydraulic fracture deflection propagation model under the influence of faults. Furthermore, the fracture propagation law was simulated and analyzed in the presence of a non-uniform in-situ stress field. The findings demonstrate that hydraulic fractures near the strike-slip fault tend to run parallel to the fault direction, whereas hydraulic fractures near the normal fault tend to run perpendicular to the fault direction. The greater the fault throw and the greater the hydraulic fracture propagation deflection angle, the closer the hydraulic fracture is to the fault. The deflection behavior of hydraulic fractures increases flow resistance in the fracture, and proppant transport does not flow smoothly, increasing the difficulty and risk of the fracturing operation. The findings of this study could provide an important theoretical foundation for the design of staged multi-cluster fracturing of horizontal wells near faults in shale formations.

Research on Wellbore Instability of Shale Formation in Extremely Complex Geo-Mechanical Environment

Borehole instability problems are commonly encountered while drilling highly deviated and horizontal shale gas wells within the shale formations associated with high-dip bedding planes. An integrated rock mechanical study is described in this paper to evaluate the risk of the borehole instability problems in this area. First, a set of uniaxial compressive tests are carried out to measure the strength of the bedding shales on cores with different angles between the load direction and the bedding planes. A critical strength criterion is then proposed based on the test results. Next, the stress state of the borehole with arbitrary inclination and azimuth is determined through coordinate transformations. Finally, through combining the strength criterion and the stress state of the borehole, the risk of borehole instability is investigated for deviated and horizontal wells in shale formations with different bedding dips (0–90°) and dip directions (45° and 90° to the direction of minimum horizontal stress σh). The results show the dependence of borehole instability on the orientation of bedding planes of the formation as well as inclination and azimuth of the well. The most desirable borehole trajectory from the viewpoint of borehole stability is at the direction normal to the bedding planes. For a horizontal well specifically, if the bedding direction is perpendicular to the direction of σh, the risk of instability is relatively high for most drilling directions except drilling along the dip direction of the bedding planes. However, if there is a moderate acute angle (e.g., 45°) between the dip direction and the direction of σh, the risk of instability is relatively low for most drilling directions unless drilling along the direction of σh.