Horizontal Gas Wells Research Articles

A simple analytical model to predict liquid unloading in the horizontal gas well

A simple analytical model to predict liquid unloading in the horizontal gas well

Shear compression deformation test and deformation prevention practice of casing in shale gas horizontal wells

With the rapid development of shale gas exploration and development in China, casing deformation in shale gas horizontal wells happens frequently, which directly impacts the development efficiency and benefits of shale gas. In order to explore casing deformation prediction, prevention and treatment methods, this paper analyzes the geological and engineering causes of casing deformation in shale-gas horizontal wells through laboratory work, such as the casing resistance to internal pressure alternating test, the ground simulation test and systematical casing deformation characteristic analysis of MIT24 caliper logging, and the large-scale physical simulation test and numerical simulation of casing deformation. Then, combined with the generalized shear activity criterion, a new method for evaluating casing deformation risk points and some technical measures for preventing casing deformation were formulated. And the following research results were obtained. First, the deformation characteristics of 119 casing deformation points in 23 wells interpreted by MIT24 caliper logging are consistent with the mechanical behaviors of shear compression deformation test. Second, the large-scale physical simulation test shows that natural fault-fractures slip obviously under the state of strike-slip stress. Third, numerical simulation shows that the compression stress on casing increases with the increase of fault-fracture slip. When the fault-fracture slip is between 7.5 mm and 9.0 mm, the casing reaches the critical yield strength and begins to undergo plastic deformation. The “temporary fracture plugging + long segment and multi-cluster” and other technologies are field tested in 28 wells in Weiyuan area of southern Sichuan Basin. The casing deformation rate decreases from 54% (before this research) to 14.3%, and the segment loss rate decreases from 7.8% to 0, which reveals remarkable achievements in casing deformation treatment. In conclusion, the shear slip of fault and macro fractures (referred to as fault-fracture) is the main cause of casing deformation in shale gas horizontal wells, and some measures (e.g. “temporary fracture plugging + long segment and multi-cluster”, reducing fracturing scale and releasing wellbore pressure properly) shall be taken in advance to reduce the fault-fracture activity before the risk point of casing deformation is fractured, so as to reach the goal of casing deformation prevention.

DTS based hydraulic fracture identification and production profile interpretation method for horizontal shale gas wells

In order to accurately evaluate the fracturing stimulation effect of horizontal wells in shale gas reservoirs, it is suggested to establish a model to predict the temperature distribution in the wellbore of horizontal well and an inversion model of DTS data by using MCMC algorithm, and optimize the production profile interpretation process. In this paper, the characteristics of temperature profile of fractured horizontal wells in shale gas reservoirs were analyzed and the main factors affecting the temperature profile were figured out. Finally, the newly established inversion model was applied to the production profile interpretation of one case well in a certain shale gas reservoir. And the following research results were obtained. First, the temperature profile of fractured horizontal wells is in the shape of irregular “saw tooth”, and each “saw tooth” corresponds to an effective hydraulic fracture with fluid inflow. Second, the longer the fracture is, the greater the wellbore temperature drop at the corresponding fracture location is, and the gas flow rate in the fracture is positively correlated with the temperature drop. Third, from the perspective of influence degree, the factors influencing the temperature profile of fractured horizontal wells in shale gas reservoirs are ranked from the strong to the weak as follows: fracture half-length, gas flow rate, permeability of stimulated area, wellbore diameter, fracture conductivity, horizontal inclination angle, and comprehensive thermal conductivity, among which, the first three are main controlling factors. Fourth, the MCMC inversion method is applied to invert the DST temperature data of the case well. The temperature profile predicted in the model is better accordant with the measured DTS profile, and the absolute error of the predicted temperature at different levels of effective hydraulic fractures is less than 0.02 °C. The interpreted gas flow rate of each fracturing stage is closer to the field measurement, and the deviation of the maximum gas flow rate of a single fracturing stage is only 180.35 m3/d. The absolute error between single-well gas production rate and gas production rate measured at the wellhead is less than 3 m3/d, which proves the reliability of this newly developed inversion model.

Drainage effect of internal vortex tool based on experiment and numerical simulation

ABSTRACT The liquid loading at the bottom of horizontal gas well is a problem that has a significant influence on the productivity of gas well. Therefore, it is necessary to take some measures of drainage gas recovery to reduce liquid loading in wellbore and increase gas production. To evaluate the drainage effect of the internal vortex tool, which is a new drainage gas recovery tool, firstly, under the conditions of different water-gas ratios, a horizontal well laboratory simulation experiment device was used to simulate the flow state and liquid loading of the gas-liquid two-phase fluid in the wellbore before and after loading the internal vortex tool. The experimental results indicate that the internal vortex tool can effectively decrease wellbore liquid loading, improve wellbore fluid flow pattern and reduce production pressure drop. Secondly, the numerical simulation method is used to study the flow of gas-liquid two-phase and pressure drop amplitude under different gas and liquid flow conditions. Finally, the results of laboratory experiment were compared with numerical simulation, and it was found that the pressure drop amplitude error was between 6.18%~9.32%, both within 10%, which met the error requirements. It was proved that the application of internal vortex tool could effectively increase the productivity of gas wells.

Casing Collapse Strength Analysis under Nonuniform Loading Using Experimental and Numerical Approach

Multistage fracturing is the main means of shale gas development, and casing deformation frequently occurs during fracturing of shale gas horizontal wells. Fracturing fluid entering the formation will change in situ stress nearby the wellbore. The changes of in situ stress are mainly reflected in the following two aspects: one is the increase of in situ stress and the other is the nonuniformity of in situ stress along the wellbore. And it is for this reason that the production casing is more likely to collapse under the nonuniform in situ stress load. According to the service conditions of production casing in shale gas reservoir, this paper studied the casing deformation and the collapsing strength subjected to the nonuniform loading by the experimental and numerical simulation method. The results show that under the condition of nonuniform loading, (1) the diameter variation rate of the casing reduces with the increase in the ratio of sample to tooling length. When the ratio is less than 3, the casing collapse strength will be significantly reduced. And when the ratio is greater than 6, the impact of sample length on casing collapse strength can be ignored. (2) The increase in the applied loading angle will decrease the diameter variation rate. When the loading angle increases from 0° to 90°, the critical load value increases from 1600 kN to 4000 kN. (3) The increase in load unevenness coefficient will rapidly decrease the casing collapse strength. When the load unevenness coefficient n is 0.8, the casing collapse strength reduces to 60%, and when the load unevenness coefficient n is 0, the casing collapse strength reduces to 28%. The findings of this study can help for better understanding of casing damage mechanism in volume fracturing of shale gas horizontal well and guide the selection of multistage fracturing casing type and fracturing interval design.

Key Technologies for Deep Horizontal Well Drilling of Shale Gas in Luzhou of Sichuan Basin

The drilling of deep shale gas horizontal wells in Luzhou block of Sichuan Basin has been chanllenged by long drilling cycle, low rate of penetration (ROP), high drilling tool vibration, poor drillability of special lithological formations, horizontal wellbore instability, high formation temperature, and high friction torque and sticking risk etc.. To solve these problems and to ensure operation safety and increase cost-efficiency, technological research was carried out on casing program design of horizontal wells, wellbore trajectory control and optimization of horizontal sections. As a result, the optimal parameters of the radical drilling method were recommended, and shock absorption, speed-up, and high efficient rock breaking technologies for special lithological formations were preferentially adopted. In addition, drilling fluid system and performance parameters were recommended based on pilot tests of ground cooling equipment. In this way, key drilling technologies with high operation safety and efficiency were formed for the deep shale gas horizontal wells in Luzhou block. Through the application of the key technologies in four wells in Luzhou block, the experimental results show that the drilling cycle was redcued by 14.5% and no downhole failure was reported for average well depth of 5,601.00 m and the horizontal section length of 1,884.00 m. So these technologies can meet the requirement of safe and efficient drilling as well as wide application scope in Luzhou.

Research on the influence of strike-slip fault slippage on production casing and control methods and engineering application during multistage fracturing in deep shale gas wells

Shear deformation often occurs during multistage fracturing of shale gas worldwide, increasing the operation cost of gas well completion and lowering the well’s productivity; strike-slip fault slippage is thought to be a crucial underlying factor. This paper presents a detailed analysis of the influence of strike-slip fault slippage on casing inner diameter and establishes a technique for predicting casing inner diameter after fault slippage. Numerical simulation models were developed to simulate the process of fault slippage and calculate changes in the inner diameters of the casing, considering different engineering and geological conditions. The influential factors, including the fault strike angle, slip distance, radius-thickness ratio, and mechanical properties of the formation, were analyzed in engineering practice; the simulation results were shown to be consistent. Four methods, including adjusting the wellbore trajectory of shale gas horizontal wells, avoiding perforation at the formation interface, decreasing the fracturing parameters including the fracturing pressure, discharge capacity, volume of injecting fracturing fluid, and prediction of casing inner diameter after casing shear deformation, were proposed and verified through engineering application and theoretical calculation, respectively.

Improving displacement efficiency by optimizing pad fluid injection sequence during primary cementing of eccentric annulus in shale gas horizontal wells

Displacement efficiency of horizontal wells is mainly affected by casing eccentricity and slurry column structure in the wellbore, and it is an essential precondition for ensuring primary cementing quality. Most current studies use annulus two-phase flow to study the effect of eccentricity on displacement efficiency. In actual cementing conditions, there is multi-phase fluid displacement in the wellbore, including mud, spacer, flusher, and cement. In this study, the computational fluid dynamics (CFD) method is used to analyze three-phase displacement in different eccentric annuli of horizontal wells. An annulus with an eccentricity of 0.4 was selected to simulate different pad fluid injection sequences in the displacement process. The results show that the eccentricity of horizontal wells results in uneven flow velocity on the wide and narrow sides, and higher casing eccentricity results correspondingly in more mud retention volume. While the coupling effect of eccentricity and buoyancy reaches the critical equilibrium state, the displacement interface tends to be short and stable. With an eccentricity of 0.4, the efficiency of three-phase displacement is 85.88%, while the efficiency of four-phase displacement (mud-spacer-flusher-cement) reaches 89.67%. After increasing the volume of cement usage to one and a half annular volumes, the displacement efficiency increases to 95.16%. The results of this study allow better understanding of the casing eccentricity effect, the complex flow physics involved in the combination of spacer and flusher displacement, and optimization of the pad fluid injection sequence to obtain maximum cement displacement efficiency during primary cementing in horizontal wells. • A 3D physical model of the eccentric annulus of horizontal wells is developed. • The displacement process for three-phase fluid in the different eccentric annuli is analyzed. • Different pad fluid injection sequences in the four-phase fluid displacement process are studied. • Displacement efficiency reaches over 95% after pumping one and a half annular volumes of cement.

Study on the optimal design of volume fracturing for shale gas based on evaluating the fracturing effect—A case study on the Zhao Tong shale gas demonstration zone in Sichuan, China

Hydraulic fracturing is the key technology in the development of shale gas reservoirs, and it mainly adopts volume fracturing technology to communicate hydraulic fractures with natural fractures to increase the drainage area. In view of the difficulty in characterizing the complex fractures created by multistaged fracturing in horizontal shale gas wells and the immaturity of fracturing optimization design methods, this study first evaluated the stimulation effect of fracturing technology based on treatment data and microseismic data. Then, the fracture characteristics after frac were considered, and a post-frac simulation was studied based on the discrete fracture network (DFN) model and the microseismic monitoring data as constraints. Finally, from the simulation results, an optimal design method of volume fracturing for shale gas was proposed based on the evaluation of the frac effects. The National Shale Gas Demonstration Zone in Zhaotong, Sichuan Basin was used as an example to study the optimal frac design of shale gas wells. The results show that (1) after optimizing the design, the optimal interval range is 50–70 m, the liquid volume of a single stage is 1800–2200 m3, the amount of sand is 80 m~120 t, and the slurry rate is 10–12 m3/min. (2) Two different frac design schemes were implemented in two wells on the same platform, and the production of the optimized design scheme was 14.7% greater than the original scheme. Therefore, the frac optimization design based on evaluating the fracturing effect can better guide the development of subsequent shale gas wells in this area.

Oil-Based Drilling Fluid Plugging Method for Strengthening Wellbore Stability of Shale Gas

Finding out the reasons for wellbore instability in the Longmaxi Formation and Wufeng Formation and putting forward drilling fluid technical countermeasures to strengthen and stabilize the wellbore are very crucial to horizontal drilling. Based on X-ray diffraction, electron microscope scanning, linear swelling experiment, and hot-rolling dispersion experiment, the physicochemical mechanism of wellbore instability in complex strata was revealed, and thus, the coordinated wellbore stability method can be put forward, which is “strengthening plugging of micropores, inhibiting filtrate invasion, and retarding pressure transmission.” Using a sand bed filtration tester, high-temperature and high-pressure plugging simulation experimental device, and microporous membrane and other experimental devices, the oil-based drilling fluid treatment agent was researched and selected, and a set of an enhanced plugging drilling fluid system suitable for shale gas horizontal well was constructed. Its temperature resistance is 135°C and it has preferable contamination resistibility (10% NaCl, 1% CaCl2, and 8% poor clay). The bearing capacity of a 400 μm fracture is 5 MPa, and the filtration loss of 0.22 μm and 0.45 μm microporous membranes is zero. Compared with previous field drilling fluids, the constructed oil-based drilling fluid system has a greatly improved plugging ability and excellent performance in other aspects.

Numerical Investigation on Gas Accumulation and Gas Migration in Enlarged Boreholes of Horizontal Gas Wells

The horizontal section of the horizontal gas well will form a horizontally enlarged borehole due to factors such as the collapse of the well wall, and it is easy to form gas accumulation in the enlarged section, which will cause accidents such as overflow. Therefore, it is very important to study the gas accumulation law in the horizontal enlarged section. Based on the actual horizontal wellbore size, a three-dimensional horizontal rectangular-enlarged borehole model and a three-dimensional horizontal curved-enlarged borehole model are established in this paper to simulate the phenomenon of gas clustering in the enlarged diameter section. The research results show that, under the same length of the enlarged section, the gas discharge of the horizontally rectangular-enlarged borehole is difficult, which is more likely to cause gas accumulation, but the horizontally curved-enlarged borehole is less likely to cause gas accumulation; When the fluid flows through the horizontal enlarged diameter section, the pressure will increase and the pressure flowing out of the expansion section will decrease, and the faster the flow velocity, the greater the pressure in the expanding section.

Research and engineering application of pre-stressed cementing technology for preventing micro-annulus caused by cyclic loading-unloading in deep shale gas horizontal wells

Shale gas exploration and development maintained good momentum, but it has some problems at the same time urgently need to be solved, such as sustained casing pressure (SCP), which brought a lot of safety issues and shortened the well service lifetime. A series of experimental investigations and numerical studies were carried out to analyze the development of the micro-annulus width of the second interface in the casing-cement sheath-formation assembly before and after using the pre-stressed cementing technology. Triaxial compression tests computed tomography scanning and accumulated plastic strain tests were conducted to evaluate the residual strain under the combined action of cyclic loading-unloading and confining pressure. Full-size cement sheath experiments were performed to quantify the width critical value of the micro-annulus when gas leakage began during multistage fracturing. The corresponding numerical models of the full-size cement sheath physical simulation facility and pre-stressed cementing technology of a real deep shale gas well were developed. Different combinations of factors were analyzed to quantify the variation of micro-annulus and tolerance ability of fracturing section numbers. The influence of a series of factors, including casing inner pressure, pre-stressed loading, and mechanical parameters of the cement sheath, were analyzed. The result of the research showed that the reduction of casing pressure and increase of pre-stressed loading could help to maintain the seal integrity of the cement sheath. Micro-annulus risks can be reduced through lowering elasticity modulus and raising Poisson's ratio. Eight deep horizontal shale gas wells were cemented with pre-stressed loading. The practical application results showed there was no SCP in prior and post-multi-stage fracturing, which proved the effectiveness of this method.

Investigation of Productivity Prediction Method for Horizontal Wells in Gas Reservoirs with Closed Bottom and Top Boundaries

This study aims to predict the productivity of an open-hole horizontal gas well (OHHGW) in a gas reservoir with closed bottom and top boundaries (GRCBTBs). First, according to the theory of mirror imaging, an OHHGW in GRCBTBs is transformed into an infinite well array in infinite formation. Second, based on conformal transformation principle, the infinite well array is transformed into two production and two injection wells in the complex plane. Finally, according to the superposition principle of potential, a new productivity prediction method, which is suitable for the horizontal well in GRCBTBs, was developed. The field measured data of Jingbian gas field of Ordos Basin demonstrate the ability of the method to accurately predict the productivity of the OHHGW in GRCBTBs, and the prediction relative error of absolute open flow of well Longping 1 is only 1.03%, that is to say that the method proposed in this study has a certain guiding significance for the development of horizontal wells in GRCBTBs.

A simple and robust model for prediction of liquid-loading onset in gas wells

Accurate prediction of liquid loading is of great importance for production optimisation in gas wells. In this paper, the authors present a simple and accurate empirical model based on attached-film reversal for predicting liquid-loading onset in vertical and horizontal gas wells. Unlike established and complicated analytical models based on force balance, this model is developed from the empirical flooding equation by matching the experimental data from previous studies. Further, this model adopts the Belfroid angle-correction term for horizontal gas wells. Compared with the traditional entrained-droplet models, this model considers the effect of pipe diameter and liquid velocity. This study investigated the effect of pressure on the predicted critical gas velocity and scaled up low pressure by comparing some other analytical models. This model was also validated against the experimental data and field data. Results show that the presented model is capable of accurately predicting liquid-loading onset in gas wells. [Received: December 4, 2018; Accepted: December 13, 2019]

An experimental study of liquid unloading in the curve section of horizontal gas wells

Liquid unloading is a very common and important issue in horizontal gas wells, and the presence of curve sections increases the complexity of the phenomenon and its study. Liquid loading in a gas well will sharply reduce production, therefore, the liquid-unloading onset of different curved pipes is essential to gas production. In this work, liquid-unloading onset experiments were conducted in curved pipes with different curvatures. Then, the critical gas velocityVsgCRcan be determined according to the measured pressure gradients, liquid holdup, and liquid film reversal. This work analyzes the factors which will lead to the liquid unloading and explores the trend of the pipe curvature’s influence on the liquid unloading under laboratory conditions. The experimental results show that the critical gas velocity rises with the increase of pipe curvature, the increase is mainly due to the centrifugal force. The present work also compares the predicted results of the OLGA model and Beggs–Brill model with experimental data. The comparison results indicate that both models fit relatively well to the experimental data at the low superficial gas velocity, and both models have poor performance at high superficial gas velocity. The OLGA model fits the experimental data better than the Beggs–Brill model at high superficial gas velocity. The error analysis shows that most of the predicted data is not in good agreement with experimental data. Some errors between experimental data and calculation results are out of the range of 50%.

A new approach for gas-water flow simulation in multi-fractured horizontal wells of shale gas reservoirs

Shale gas reservoirs demonstrate low matrix porosity and permeability, and show obvious heterogeneity due to the existence of natural fractures. During the production process, fracturing fluid can easily invade the reservoir and result in a low fracturing flowback rate. The existing numerical methods are troublesome and have poor convergence. Therefore, it is necessary to develop a new approach to study the gas-water two-phase flow in shale gas reservoirs. In this paper, fractal theory is used to quantitatively characterize the heterogeneous fractures. A Mathematical model considering fractal induced-fracture distribution and gas-water two-phase flow in shale reservoirs is established. The meshless weighted least squares (MWLS) method is applied, for the first time, to the numerical simulation of gas-water two-phase flow in multi-fractured horizontal wells of shale gas reservoirs. Based on the moving least squares approximation, the variation principle is derived in detail. A numerical model of gas-water two-phase flow in the shale gas reservoir fracturing horizontal well based on the meshless method is obtained. The gas and water production of fractured horizontal shale gas wells are predicted by the model. The model simulation results are found to be in good consistent with the mathematical calculation results obtained through finite difference method. but the proposed new approach shows significant higher calculation efficiency. In addition, by applying this new approach, The influences of fracture distribution, initial water saturation, and reservoir reconstruction degree on the utilization range and production were also systematically compared and analyzed. The results showed that the smaller the fracture fractal index a in the reservoir reform area, the lower the pressure, the higher the daily gas production and the daily water production, indicating that the fracture network is densely distributed and the production effect is better. The larger the initial water saturation resulted in the greater flow resistance of the gas phase and the decrease of daily gas production. When the fracture spacing decreases in reservoir reconstruction, the daily gas production increases, but the increase range is gradually reduced and it has little effect on the daily water production.

“Unsteady intermittent coordination mechanism” of adsorbed gas desorption and transport in the late stage of shale gas development

The desorption of adsorbed gas and its diffusion in nano-channels are important mechanisms for the late stage of shale gas development. However, there is no commonly accepted theory to reveal the laws of these mechanisms in sustaining appreciable shale gas production after relatively high flow period. Experimental simulation of shale gas production and its sound theoretical deduction are capable of providing useful in-situ development guidance. In this paper, experiments are carried out to simulate the depletion production performance of horizontal shale gas wells and to explore the production laws and scientific explanations. By establishing the resemblance between the physical experiment and the in-situ development, the high matching of experimental results and real production data is realized, making the reliable prediction of gas production performance happen. It is found by the experimental results that the production of shale gas wells in the middle and late stages is dominated by a special gradual release mechanism, which is named “unsteady intermittent coordination mechanism” in this work. This special mechanism is mainly restricted by the gas mobility in shale nanopores and the supply and transport capacity in the pore-fracture system. In view of adsorption/desorption, the late-stage production characteristics are largely dependent on the adsorption and desorption processes, and the unsteady mechanism of adsorbed gas desorption is preliminarily revealed from the microscopic viewpoints of desorption laws at different pressures and in different pores. Interestingly, the desorption itself is predicted to be unsteady in essence. In terms of mobility, the transport of desorbed gas in single channels and pore networks undergoes a slow cycle of molecular accumulation and release due to the presence of wall confinement in the microscopic pores. After flowing into the fracture system, the gas will be quickly diverted to the production well. Meanwhile, the fracture system cannot be supplemented in time by gas in the micro-nano pores. To sum up, a qualitative understanding and scientific explanation of the “unsteady intermittent coordination mechanism” of the adsorbed gas desorption and transport in the late stage of shale gas development are realized.

Effect analysis of borehole microseismic monitoring technology on shale gas fracturing in western Hubei

Hydraulic fracturing technology is an important means of shale gas development, and microseismic monitoring is the key technology of fracturing effect evaluation. In this study, hydraulic fracturing and microseismic monitoring were simultaneously conducted in the Eyangye 2HF well (hereinafter referred to as EYY2HF well). The target stratum of this well is the second member of the Doushantuo Formation of the Sinian System, which is the oldest stratum of horizontal shale gas wells in the world. A total of 4341 microseismic fracturing events were identified, and 23 fracturing stages of the well were defined. The fluctuation of the number of events showed a repeating “high-low” pattern, and the average energy of these events showed minimal differences. These findings indicate that the water pressure required for the reconstruction of the EYY2HF well is appropriate. The main body of the fracture network extended from northwest to southeast, consistent with the interpretation of regional geological and seismic data. The stimulated rock volumes showed a linear increase with the increase of the fracturing stage. Some technological measures, such as quick lift displacement, quick lift sand ratio, and pump stop for secondary sand addition, were adopted during fracturing to increase the complexity of the fracture network. Microseismic fracture monitoring of the well achieved expected effects and guided real-time fracturing operations and fracturing effect evaluation.

Integrity tests of cement sheath for shale gas wells under strong alternating thermal loads

During large-scale hydraulic fracturing in shale gas horizontal wells, a cement sheath easily loses its integrity due to the fluctuation and continuous change of wellbore temperature and pressure and the cyclic loading and unloading, which will threaten wellbore integrity. In order to figure out the failure mechanism of cement sheath integrity under strong alternating thermal loads and prevent the failure of cement sheath barriers during large-scale hydraulic fracturing in shale gas horizontal wells, this paper adopted the independently developed experimental device to test and evaluate the sealing integrity and mechanical integrity of the full-scale combination of production casing, cement sheath and intermediate casing under strong alternating thermal loads. And the integrity experimental results of two kinds of full-scale cement sheaths (conventional and high-strength cement sheaths) under three kinds of strong alternating thermal loads (cycle number for the occurrence of discontinuous CO2 bubble: 4 and 14; cycle number for the occurrence of continuous CO2 bubble: 5 and 15; alternating thermal load: 30–120 °C and 30–150 °C) were obtained. And the following research results were obtained. First, alternating thermal load has a significant negative impact on the integrity of cement sheath, and with the increase of alternating temperature and temperature difference, the thermal cycle number characterizing the sealing integrity of cement sheath reduces sharply. Second, the interfacial mechanical property indicators that characterize the shearing force between cement sheath and casing and the axial and radial bonding strength decrease with the increase of the alternating temperature. Third, the micro annulus in cement sheath is mainly caused by discordant deformation between the casing and the cement sheath materials, and the mechanical degradation and deterioration of the set cement induced by the alternating thermal load aggravate the failure of the sealing integrity of cement sheath to a certain degree. In conclusion, the research results can provide a reference for the design of large-scale fracturing in deep shale gas horizontal wells.

Productivity forecast for multi-stage fracturing in shale gas wells based on a random forest algorithm

ABSTRACT This study addresses the problem of low-accuracy production forecasting for horizontal shale gas wells by applying a random forest algorithm and considering both the physical reservoir parameters and the engineering fracturing parameters. Based on the interpretation of logging data, drilling data, fracturing data, and sectional production data from the Fuling shale gas field, the random forest algorithm was used to build a regression model, through partial correlation analysis and recursive feature elimination to select the optimal key influencing factors. The study revealed that the layer, cluster spacing, number of clusters, 40/70 mesh low-density ceramsite (medium sand), and total proppant are the key factors influencing sectional production, and they all have different effects on it. The random forest algorithm showed better prediction capacity than the other algorithms. Its coefficient of determination and root-mean-square error on the test set were 0.723 and 0.319, respectively, which indicates that it is an effective approach and has good generalization ability. The prediction results of the productivity regression model based on the random forest algorithm, combined with the trend surface response analysis, were used to obtain the optimal values of the six key fracturing parameters of the unfractured well.