Horizontal Gas Wells Research Articles

Well trajectory management and monitoring station position borehole

The article analyzes the selection and recommendations, as well as instructions for drilling deep directional and horizontal wells, electric drilling methods in the Western part of the oil and gas fields of Turkmenistan in order to increase oil and gas production from productive layers of the horizons of the red-colored strata. To analyze the choice of drilling deep directional and horizontal wells, materials of previously operated wells, geological and operational characteristics of deposits and the guidance document «Operating Instructions for oil and gas wells», as well as safety rules in the oil and gas industry were used. This paper provides a detailed analysis of the complexity of drilling deep directional and horizontal oil and gas wells and their specific causes, as well as recommendations for the selection of design profiles and operating instructions for different types of deflectors, as well as telemetry systems. Such work will be useful and can be used to fulfill the tasks set when drilling wells, as well as to increase the production of oil and gas wells and to develop fields with complex geological characteristics. Keywords: profile; deflections; borehole curvature; trajectory; rotor; layout; telesystem; conductor; inclinometer; deflector; azimuth.

Fluid-structure interaction characteristics between natural gas fluid and tubing string in high-pressure high-temperature high-production gas wells

The transient internal flow in high-pressure high-temperature high-production (three-high) gas wells may bring about serious fluid-structure interaction (FSI) between natural gas fluid and tubing string. Then, fatigue failure, wear and leakage of tubing string can easily be caused to threaten the wellbore safety and integrity. However, it is difficult to directly adopt the existing FSI model owing to particularity environment of the three-high gas wells. Based on water hammer, FSI and Timoshenko beam theory, a mathematical model expounding FSI phenomenon of the three-high gas wells is established by Poisson, friction and junction coupling, which considers unsteady friction effect, centrifugal and Coriolis force to make FSI characteristics more consistent with the engineering practice. Then, the improved method of characteristics (MOC) is applied into combination solution of the model. Later, the model and solution method is verified by comparing the results with different reference's ones respectively. On this basis, the effects of shut-in time, well depth position, unsteady friction on FSI characteristics are analyzed and discussed systematically. The calculation results are shown that shut-in time and well depth position have a more significant influence on FSI characteristics in three-high gas wells. In addition, FSI characteristics under action of unsteady friction decay faster, the time of the peak value also is delayed accordingly, and cumulative attenuation and cumulative delayed time of FSI characteristics increases with decrease of shut-in time. The FSI model, solution method proposed in this paper and results can provide theoretical basis and reference for the research on FSI and the formulation of shut-in operation for three-high gas wells, and even for highly deviated or horizontal gas wells.

Segmented superimposed model of near-bore reservoir pollution skin factor for low porosity and permeability sandstone horizontal gas wells

Drilling and completion processes can often result in reservoir contamination around the wellbore, leading to decreased oil and gas productivity and significant economic losses for the oil field. This issue is particularly complex in sandstone reservoirs with low porosity and permeability horizontal wells, wherein traditional models have limited accuracy and applicability due to numerous unknown parameters. To address this challenge, this study focuses on non-uniform pollution around horizontal wells and proposes a new approach to divide the horizontal well pollution area into N micro-element sections. By establishing a seepage differential equation and employing the similar flow substitution method, we construct models for the pollution skin coefficient of each micro-element section as well as the total pollution skin coefficient. Furthermore, we combine empirical equation models and an oscillation-decreasing function model to develop a pollution radius distribution model that encompasses linear, parabolic, exponential, and logarithmic patterns. Through these advancements, we can realize a comprehensive reservoir damage assessment method. It is verified that the calculation error of this model is very small, and the influence of skin effect and reservoir anisotropy and the radius distribution of various heterogeneous pollution zones are fully considered. These findings indirectly suggest the rationality and practicality of the model presented in this paper. By incorporating actual gas well data into this model, it has been determined through discussion and analysis that the exponential distribution of the pollution radius has the greatest impact on the pollution skin factor along the horizontal well, from the heel to the toe. Increasing the pollution radius and decreasing the pollution permeability both result in an increase in the skin factor of the micro-segment and the total pollution skin factor of the horizontal well. However, compared to the pollution permeability, the radius of the pollution zone has a relatively minor effect on the total pollution skin factor. The proposed technique aims to serve as a valuable tool in optimizing and designing stimulation measures aimed at boosting production and minimizing formation damage. Through evaluation and analysis to reduce risks, protect reservoirs and extend well life, reduce costs, and enhance technical capabilities and economic benefits.

Experimental and modeling studies on continuous liquid removal in horizontal gas wells

The potential risks of liquid-loading can be significantly decreased by precisely calculating the minimum gas flowrate required for continuous liquid removal in gas wells and using suitable deliquification technology beforehand. Due to lack of comparative studies with liquid-loading characteristics, existing prediction models are not very adaptable in the course of the application. So as to investigate the flowing behavior of liquid film under different conditions, visual experiment was conducted. The findings indicate that as the inclined angle increases, the liquid-film-reversal gas velocity increases initially before decreasing. The maximum velocity of liquid-film-reversal is around 55°. The liquid-film-reversing gas velocity increases linearly along with the rise in superficial liquid velocities. The liquid-film-reversal gas velocity likewise increases linearly as the superficial liquid velocities. The analysis findings also indicate that several dynamic liquid-loading symptoms of the gas well are inconsistent with the liquid-film-reversal criterion, meaning that the gas well does not instantly follow the liquid-film-reversal. On the basis of our experimental findings, a new liquid-loading commencement criteria was then developed. As a result, this research suggests a novel model for evaluating liquid-loading in gas wells. The model’s accuracy was found to be as high as 85.7% by looking at 14 gas wells and perform better than other models in the Coleman dataset, which can theoretically enable the prediction of liquid-loading in gas wells.

Evaluation of the controlling effect of new annulus materials on casing deformation in shale gas wells

Shale gas horizontal wells have severe problems of casing deformation and failure due to formation displacement during fracturing. Statistics show that casing deformation problems occur frequently in the development of shale gas, especially in Sichuan Basin. Furthermore, the phenomenon of formation extrusion and fault slip is serious, which has caused great obstacles to the development of shale gas in China. In view of the current lack of casing deformation control methods, a finite element model of a wellbore under formation displacement load is established in this paper. The stress and deformation of the casing are simulated, and the mitigating effects of new annular materials such as a modified cement sheath and rubber are evaluated. Results indicate that the formation extrusion and fault slip can cause radial oval deformation and axial S-shaped deformation of the production casing, respectively. The use of a modified cement sheath can provide a little mitigating effect on casing deformation. Meanwhile, using rubber cementing can play a strong protective role for the production casing and avoid casing deformation to a certain extent. This research can provide a new way and important reference for the prevention and control of casing deformation in shale gas wells.

Calculation and research of fundamental frequency of casing string in shale gas horizontal wells

In view of the fact that the fundamental frequency of the casing string in shale gas horizontal wells is difficult to be accurately obtained by numerical simulations and experimental methods, a research method is proposed based on the similarity model theory and the transfer matrix method. According to the similarity criterion from the similarity theory, a similarity model is established, and the similarity ratio of the natural frequency is obtained. Through the use of the transfer matrix method, the fundamental frequency of the experimental model of the casing string in horizontal wells with rigid support is analyzed, and its mathematical model is established. Through the calculation of the fundamental frequency of the experimental model and the result of the vibration experiment, the correctness of the model is verified. Besides, the fundamental frequency of a 2500 m long shale gas horizontal well casing string with 20 rigid centralizers is calculated. The calculation results show that the combination of the similarity theory and the transfer matrix method can realize the solution of the natural frequency of the casing string in large-scale horizontal wells, which is reliable, accurate and easy to be programmed.

Wide azimuth seismic data processing technology and application: a case study of tight gas reservoirs in western China

As the difficulty of oil and gas field exploration and development increases both domestically and internationally, onshore exploration targets have gradually shifted from the shallow to the deep and from conventional oil and gas reservoirs to unconventional ones. Particularly in the exploration and development of unconventional oil and gas horizontal wells, there is an increasing demand for higher precision and quality of seismic data to better identify formation lithology, rock fractures, and improve the characterization of reservoirs, reservoir positioning, and connectivity. Wide-azimuth seismic exploration possesses significant technical advantages in addressing exploration challenges such as lithologic exploration, small fault imaging, and detailed characterization of oil and gas reservoirs. Wide azimuth seismic data reduces blind spots in seismic acquisition and improves the imaging accuracy of small faults. Notably, there exist distinct anisotropic characteristics in fault areas and fractured reservoirs. Wide azimuth seismic data is particularly advantageous for studying amplitude variation with variations in amplitude with offset (AVO), incident angle (AVA), or azimuth (AVAZ), as well as velocity with azimuth (VVA). These variations aid in identifying faults, fractures, and changes in formation lithology. As the focus of oil and gas exploration gradually shifts to complex lithological reservoirs and unconventional oil and gas reservoirs, narrow azimuth seismic exploration has been gradually replaced by wide azimuth exploration. However, as observation azimuth increases, challenges related to velocity variations with azimuth, azimuth-related traveltime differences, and azimuth-related anisotropy arise. Based on wide-azimuth seismic data from tight gas reservoirs in western China, this study conducted wide-azimuth anisotropic velocity analysis, OVT domain data regularization processing, OVT domain prestack time/depth migration, and horizontally transverse isotropy (HTI) azimuth anisotropy correction techniques. After applying specialized processing to the wide-azimuth seismic data, significant improvements were observed in the S/N and resolution of the target layer. The delineation of fractures related to hydrocarbon sources also became more distinct. These advancements not only provided high-quality results for high-fidelity, high-resolution imaging of tight gas reservoirs but also provided azimuth volume corresponding to fast and slow wave velocities for seismic data interpretation, facilitating velocity variation with azimuth (VVAZ) fracture detection and AVO analysis research.

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.

Prediction of Liquid Holdup in Horizontal Gas Wells Based on Dimensionless Number Selection

Abstract Pressure gradient prediction is crucial in gas well analysis. The experiment is the most effective method of understanding the flow characteristics in horizontal gas wells. The greatest difference between experimental and high-pressure conditions is gas density, which could cause the established multiphase correlations unreliable when they are applied to high-pressure gas wells. Similarity numbers are widely employed in predicting flow behavior. Nevertheless, few studies focused on this area. In addition, gas wells are characterized as high gas–liquid ratio; the majority empirical correlations were developed for oil wells, which have more consideration in low gas–liquid ratio, influencing the precision of gas well models. An experimental examination of gas–liquid flow has been carried out in this study. First, the experimental test matrix was designed to meet each flow pattern. Next, the effect of gas velocity, liquid velocity, pipe diameter, water-cut, and inclined angle on liquid holdup was explored. Subsequently, the similarity numbers suggested have been investigated and assessed for pressure scaling up. Finally, a comprehensive model was established, which was developed to forecast pressure gradient in gas wells. Field data were supplied to assess the new correlation. The results demonstrated that the Duns–Ros and the modified Duns–Ros dimensionless numbers were improper for pressure scaling up, whereas the Hewitt–Robert Number performs best. Based on the field data, the new correlation with Hewitt–Robert Number was superior to extensively employed pressure drop correlations, showing that it can deal with predicting pressure gradient in gas wells.

Simulation Experiment and Mathematical Model of Liquid Carrying in the Entire Wellbore of Shale Gas Horizontal Wells

Shale gas is mostly produced using horizontal wells, since shale gas reservoirs have low porosity and permeability. It is challenging to predict a horizontal well’s critical liquid-carrying gas flow rate because horizontal wells have more complicated well structures and gas–liquid two-phase pipe flows than vertical wells. In addition, there are significant differences between shale gas reservoirs and conventional natural gas reservoirs as well as dynamic changes in the liquid production rate. The majority of critical liquid-carrying models currently in use in engineering are based on the force analysis of droplets in the gas stream or liquid film on the pipe wall in annular-mist flow in the vertical wellbore. However, they do not take into account the impact of changes to the entire wellbore structure and dynamic changes in the liquid production rate on gas–liquid two-phase flow patterns and liquid carrying in the wellbore. In order to perform the critical gas velocity test for liquid carrying in the entire wellbore of horizontal wells, a visual liquid-carrying simulation experimental device for the entire wellbore of horizontal wells and a high-speed camera were used in this study. The onset of liquid accumulation was analyzed comprehensively according to the overall increase of the wellbore liquid and the change of the system pressure. A modified K–H wave theory liquid-carrying model was developed by taking into account the impacts of liquid production rate and well inclination angle based on the experimental data, the K–H wave theory, the cross-section actual gas velocity, and the angle correction correlation formula. The improved liquid-carrying model is in good accordance with the test findings, according to the experimental results. In Shunan Gas Mine, Sichuan, China, there are eight deep shale gas wells, which produced a total of 25 sets of tests. The modified model was used to forecast and diagnose the liquid-carrying capacity in the entire wellbore of these wells. The diagnosis results are in good agreement with the actual production situation, and the coincidence rate is 92%.

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.

Study of Estimated Ultimate Recovery Prediction and Multi-Stage Supercharging Technology for Shale Gas Wells

The development of shale gas reservoirs often involves the utilization of horizontal well segmental multi-stage fracturing techniques. However, these reservoirs face challenges, such as rapid initial wellhead pressure and production decline, leading to extended periods of low-pressure production. To address these issues and enhance the production during the low-pressure stage, pressurized mining is considered as an effective measure. Determining the appropriate pressurization target and method for the shale gas wells is of great practical significance for ensuring stable production in shale gas fields. This study takes into account the current development status of shale gas fields and proposes a three-stage pressurization process. The process involves primary supercharging at the center station of the block, secondary supercharging at the gas collecting station, and the introduction of a small booster device located behind the platform separator and in front of the outbound valve group. By incorporating a compressor, the wellhead pressure can be reduced to 0.4 MPa, resulting in a daily output of 12,000 to 14,000 cubic meters from the platform. Using a critical liquid-carrying model for shale gas horizontal wells, this study demonstrates that reducing the wellhead pressure decreases the critical flow of liquid, thereby facilitating the discharge of the accumulated fluid from the gas well. Additionally, the formation pressure of shale gas wells is estimated using the mass balance method. This study calculates the cumulative production of different IPR curves based on the formation pressure. It develops a dynamic production decline model for gas outlet wells and establishes a relationship between the pressure depletion of gas reservoirs and the cumulative gas production before and after pressurization of H10 −2 and H10 −3 wells. The final estimated ultimate recovery of two wells is calculated. In conclusion, the implementation of multi-stage pressurization, as proposed in this study, effectively enhances the production of, and holds practical significance for, stable development of shale gas fields.

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.

Waste to Energy: Review on the Development of Land Fill Gas for Power Generation in Sub-Saharan Africa

This study focused on the development of land fill gas for power generation in Sub-Saharan Africa. In rapidly expanding cities in developing and emerging nations, it has been observed that municipal solid waste (MSW) has increased dramatically, raising public concern about the effects on the environment and public health. In Sub-Saharan Africa today, the garbage of people within this region especially in Nigeria is carelessly disposed. Environmental pollution and its effects on people's quality of life have become more sensitive topics among residents and decision-makers in Sub-Saharan Africa. Additionally, municipal solid waste management (MSWM) is becoming a more important topic on the local political agenda. Local decision-makers routinely debate whether to invest in waste-to-energy technologies as part of their effort to modernize waste management systems. Waste-to-Energy technologies are being promoted more and more as an alluring solution to a number of problems, including the urgent issue of waste disposal. These issues include inadequate power production, a shortage of landfill space, and greenhouse gas emissions from improper waste management. As an alternative to waste burning and composting, landfilling is one of the municipal solid waste (MSW) disposal techniques that are most frequently used. Due to its financial benefits, the sanitary landfill method is still often employed in various nations for the final disposal of solid waste. Landfill gas (LFG) is mostly produced by the anaerobic breakdown of the biodegradable component of municipal solid waste (MSW), specifically kitchen and yard trash, which is disposed of in landfills. Due to the anaerobic breakdown of the organic portion of solid waste, landfill gas is continuously produced. As a result, if an extraction system is not constructed in a landfill, there will be an overpressure that will force the biogas to be released into the atmosphere, which will have an adverse effect on the environment. Methane and carbon dioxide make up the majority of the gases that make up landfill gas, which is a mixture of other gases. Many landfill sites include an operational gas collection system that draws gas from both horizontal and vertical gas wells using a blower. The gas from the landfill was thought to only include carbon dioxide and methane. Methane's typical volume composition is 49%, hence it was believed that carbon dioxide would have a volume composition of 51%. Reviewing the information gathered by numerous studies regarding the volume of waste being dumped in landfills reveals that the waste produced in sub-Saharan Africa is sufficient to power the area with electricity. It was discovered that the quantity of electricity generated will fluctuate over time based on the flow rate of landfill gas. It will initially rise until a peak is attained. A million tons of landfill waste typically emits 434,000 cubic feet of LFG each day, which is sufficient to generate 0.80 MW of power. About 70% of LFG projects use internal combustion engines, gas turbines, and micro-turbines to produce power.

Flowback and early-time production modeling of unconventional gas wells using an improved semi-analytical method

Multiple fractured horizontal wells (MFHWs) currently are the only possible means of commercial production from the low and ultra-low permeability unconventional gas reservoirs. In early production time, flowback fluid, which constitutes of hydraulic water and gas flow within fractures, is collected and analyzed. Flowback analysis has been shown to be a useful tool to estimate key properties of the hydraulic fracture such as conductivity and pore volume. Until date, most tools of flowback analysis rely on empirical and approximate methods. This study presents an improved Green-function-based semi-analytical solution for performance analysis of horizontal gas wells during flowback and early production periods. The proposed solution is derived based on coupling the solutions of two domains: a rigorously derived Green’s function-based integral solution for single-phase gas flow in matrix, and a finite-difference, multiphase solution for gas–water two-phase flow in the fracture. The validity of proposed semi-analytical solution is verified by finely gridded numerical models built in a commercial simulator for a series of synthetic cases considering a variety of fluid and reservoir property combinations, as well as various different production constraints. Comparisons against available empirical and approximate methods are also provided for these cases.

Analysis of casing stress during multistage fracturing of shale gas horizontal wells considering thermo‐hydro‐mechanical coupling

AbstractDuring the multistage fracturing of shale gas horizontal wells, casing damage frequently occurs, making it essential to evaluate casing stress and deformation. This paper establishes a mathematical model of thermo‐hydro‐mechanical coupling and a finite element model of casing‐cement sheath‐formation (CCF). This paper examines the effects of temperature, casing thickness, nonuniform in situ stress, mechanical properties of cement sheath, and treating pressure on the stress and deformation of CCF. Finally, the study investigates the variation of local in situ stress at the heel and casing stress from toe to heel. The results show that the low temperature of CCF, high elastic modulus of cement sheath, small casing thickness, high treating pressure, and large nonuniform in situ stress can exacerbate casing stress. After pumping off, the local in situ stress and its nonuniformity near heel gradually increased, and the effective stress of casing increases compared with the pumping on the process. As the fracturing stages increase, the effective stress of casing at heel increases, and the casing at heel preferentially damages. The results provide a theoretical basis and guidance for maintaining wellbore integrity and preventing casing damage in the multistage fracturing of shale gas horizontal wells.

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.

A Modified Model to Predict Liquid Loading in Horizontal Gas Wells

Abstract Liquid loading is inevitable during mature gas-well production, leading the liquids to accumulate at the bottomhole and additional pressure loss. Accurately predicting the liquid-loading initiation is crucial to gas-well production optimization. Significant efforts have been made to model liquid-loading behavior. However, few mechanistic models are capable of easily and accurately tackling the complicated non-uniform liquid-film distribution in the slanted section of horizontal wells. Based on liquid-film inversion, this study developed a simple and comprehensive model to calculate liquid-loading initiation for horizontal gas wells. First, the models for film thickness and critical velocity in the vertical pipe are developed. Then, considering the effect of inclination and velocity difference in liquid-film thickness and liquid-holdup distribution between vertical and inclined pipes, the relationship in vertical and inclined pipes between liquid holdup, liquid-film thickness, and angle correction term is established based on the liquid-holdup correlation for horizontal and inclined pipes described in the empirical model developed by Beggs and Brill, so that the thickness of the film and the corresponding critical velocity at any inclination can be calculated. Finally, the new modified model has been evaluated against both experimental and field-measured data set. In comparison to the Luo et al.’s model, the proposed model has been proven to be simple, accurate, and well-performed in predicting the liquid-accumulation initiation in horizontal wells.