Shale Gas Wells Research Articles

Time series modeling for production prediction of shale gas wells

Accurate production prediction of shale gas wells in the early stage is the key to optimizing development plans and effectively extending the life cycle of gas wells. The existing models pay less attention to the production prediction of gas wells with short production history in the early stage, and the long-term shut-in intervals in the early production process have not been taken into account. In addition, uncertainty in production forecasts is often not mentioned because of difficulties in characterizing. In this paper, a new early production prediction model is developed that integrates the long short-term memory (LSTM) model and deep learning autoregressive (DeepAR) model. The LSTM model makes a deterministic prediction of early production. At the same time, the Bidirectional LSTM (Bi-LSTM) model is applied to the interpolation of long shut-in interval data. For the problem of lag and difficult to deal with production mutation in LSTM model, DeepAR model uses probabilistic prediction to quantify the uncertainty in early production prediction. To verify the performance of the proposed model, the production time series of production case wells are analyzed. The experimental results indicate that the early production prediction model established in this paper can effectively realize the production dynamic tracking with limited production data, and can reliably quantify the uncertainty of early production prediction.

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.

Mechanisms of Stress Sensitivity on Artificial Fracture Conductivity in the Flowback Stage of Shale Gas Wells

The presence of a reasonable flowback system after fracturing is a necessary condition for the high production of shale gas wells. At present, the optimization of the flowback system lacks a relevant theoretical basis. Due to this lack, this study established a new method for evaluating the conductivity of artificial fractures in shale, which can quantitatively characterize the backflow, embedment, and fragmentation of proppant during the flowback process. Then, the mechanism of the stress sensitivity of artificial fractures on fracture conductivity during the flowback stage of the shale gas well was revealed by performing the artificial fracture conductivity evaluation experiment. The results show that a large amount of proppant migrates, and the fracture conductivity decreases rapidly in the early stage of flowback, and then the decline gradually slows down. When the effective stress is low, the proppant is mainly plastically deformed, and the degree of fragmentation and embedment is low. When the effective stress exceeds 15.0 MPa, the fragmentation and embedment of the proppant will increase, and the fracture conductivity will be greatly reduced. The broken proppant ratio and embedded proppant ratio are the same under the two choke-management strategies. In the mode of increasing choke size step by step, the backflow proppant ratio is lower, and the broken proppant is mainly retained in fractures, so the damage ratio of fracture conductivity is lower. In the mode of decreasing choke size step by step, most of the proppant flows back from fractures, so the damage to fracture conductivity is greater. The research results have important theoretical guiding significance for optimizing the flowback system of shale gas wells.

CLAP: Gas Saturation Prediction in Shale Gas Reservoir Using a Cascaded Convolutional Neural Network–Long Short-Term Memory Model with Attention Mechanism

Gas saturation prediction is a crucial area of research regarding shale gas reservoirs, as it plays a vital role in optimizing development strategies and improving the efficiency of exploration efforts. Despite the advancements in deep learning techniques, accurately modeling the complex nonlinear relationships involved in gas saturation prediction remains a challenge. To address this issue, we propose a novel cascaded model, CLAP, combining convolutional neural networks (CNNs) and Long Short-Term Memory (LSTM) with an attention mechanism. It effectively captures and visualizes the intricate nonlinear relationships, enabling accurate gas saturation prediction in shale gas reservoirs. In this study, nine logging curves from 27 shale gas wells in the Changning area of the Sichuan Basin were used to train the CLAP model for predicting the gas saturation of the Wufeng-Longmaxi Formation shale. Compared to the Archie and random forest models, the CLAP model exhibited enhanced accuracy in predicting shale gas saturation. Promisingly, the CLAP model demonstrates outstanding statistical performance in gas saturation prediction, achieving an impressive R2 score of 0.762 and a mean square error (MSE) score of 0.934. These positive results highlight the effectiveness and potential utility of our proposed CLAP model in accurately predicting gas saturation in shale gas reservoirs. The application of deep learning techniques, such as CNNs, LSTM, and attention mechanisms, presents a promising avenue for further advancements in this field.

Failure Analysis and Countermeasures for Cement Sheath Interface Sealing Integrity in Shale Gas Wells

Summary Shale gas development usually uses large displacement horizontal well and staged fracturing technology to increase operation production. The complex environmental and construction conditions often lead to wellbore sealing integrity problems in the shale gas production process. This study shows a new method for evaluating the sealing integrity of shale gas cement sheath interfaces, which aims to understand the failure mechanism during shale gas production and to propose countermeasures that can effectively improve the sealing integrity of cement sheath interfaces in shale gas cementing. The study results showed that the oil contamination of cement sheath interface will greatly weaken its sealing performance. After repeated cyclic loading, the sealing performance of the conventional and expanded cement sheath assemblies is damaged, and a gas channel is formed, which is caused by the combination of microcracks and microgaps. Furthermore, oil contamination of the cement sheath interface will accelerate its sealing failure. The addition of an expansion agent is helpful to solve the problem of microgap destruction, and the fibers or whiskers can alleviate the problem of tensile cracking. The field application in the three wells proved that the toughened expanded cement slurry significantly improved the sealing integrity of the cement sheath interface in shale gas wells. The research results can evaluate and predict the sealing performance of the cement sheath interface in shale gas wells under the conditions of staged fracturing and have some directional significance for the cement slurry system optimization in the field.

Influence of macroscopic natural fractures group on fractures network propagation in deep shale gas reservoir

The formation of macroscopic natural fractures in deep shale reservoirs exhibits significant variability and phenomena, such as severe fracturing fluid loss during fracturing and pressure channeling between wells occur frequently and significantly impact the fracturing effect of shale gas wells. We developed a model for the propagation of fracture networks in deep shale reservoirs, taking into account the presence of macroscopic natural fractures, and studied the sensitivity factors of macroscopic natural fractures group characteristic parameters to the stimulated reservoir volume (SRV). The influence of macroscopic natural fractures group characteristic parameters on SRV was quantitatively investigated. The SRV has a positive correlation with the distance between natural fracture groups and perforation positions, as well as the intensity of the macroscopic natural fractures group. Conversely, the density and approach angle of macroscopic natural fracture groups have a negative correlation with the SRV. The degree of correlation between the natural fracture group characteristic parameters and SRV is the distance between the natural fracture group and perforation positions > density > intensity > approach angle. Performing simulation of the propagation of fracture networks in deep shale, while taking into account the impact of macroscopic natural fractures group can enhance fracturing efficiency, lower fracture-related risks.

Influencing Factors of Drainage and Production and Quantitative Evaluation in Shale Gas Reservoirs

As a transitional energy source, natural gas plays a crucial role in the energy transition. In the efficient development of shale gas, the drainage and production process, as an important link between hydraulic fracturing and production, determines the recovery rate of individual wells. To clarify the main controlling factors of shale gas drainage and production, provide strategies for classification, and improve the recovery rates of individual wells, a numerical simulation method was proposed to analyze the factors affecting drainage and production, and the VIKOR method was used for quantitative evaluation of the drainage and production effects. The research results showed that: (1) The study identified nine main controlling factors affecting drainage and production performance, including gas saturation, permeability, stress difference, burial depth, formation pressure, cumulative fracture volume, final fracture loss rate, average final diversion ability, and wellbore liquid loading. (2) A workflow for quantitatively evaluating the drainage and production effectiveness of shallow shale gas wells and selecting wells with potential for optimized drainage and production was proposed. The correlation between the evaluation results and EUR fitting had an R2 value of 0.71, indicating a good level of credibility. (3) The evaluation results for the target gas field indicated that out of the 16 representative wells, 12 wells have optimization potential, with 5 wells showing significant optimization potential. Studying the rules of shale gas drainage and production and evaluating the drainage and production effects can help us to propose refined drainage and production strategies, which are essential for improving the estimated ultimate recovery (EUR).

Prediction of dynamic liquid level in water-producing shale gas wells based on liquid film model

The accumulation of liquid in shale gas wells will lead to an increase in bottom-hole pressure, and a decrease in production, even the shutdown of gas wells. Accurately predicting the variation of liquid height in shale gas wellbore and the corresponding production is helpful to determine the liquid accumulation status and the development of reasonable drainage construction plans. It can provide theoretical support for the efficient and stable production of shale gas wells. A predictive analysis model of shale gas wellbore liquid accumulation was established based on a liquid film carrying model, which considers the coupling of flow in the reservoir and wellbore in shale gas production system. This model can accurately predict the liquid accumulation height, production rate, and the bottomhole pressure changes in liquid-accumulating gas wells. A comparative analysis was conducted on the effect of wellbore structure on liquid accumulation characteristics in the typical upward-type and downward-type horizontal wells in the W block. In upward-type horizontal wells, the liquid height increases slowly before the liquid accumulation fills the horizontal section, and the liquid height increases rapidly after the liquid accumulation fills the horizontal section. Compared to upward-type horizontal wells, the liquid height rises more quickly and the gas production rate is more sensitive to liquid accumulation in downward-type horizontal wells.

Frac-Hit Prevention Countermeasures in Shale Gas Reservoirs with Natural Fractures

The development of natural fractures (NFs) in shale gas reservoirs is conducive to improving the productivity of shale gas wells. However, NF development leads to high-frequency frac hits between the infill and parent wells, which critically restricts its efficiency. To elucidate the large contribution of hydraulic fractures (HFs) and NFs in frac hits during the production and the development of NF-developed shale gas reservoirs, such reservoirs in the WY area of western China are taken as an example. A total of 197 frac hits well events in this area are systematically classified via the frac-hit discrimination method, and the effects of different factors on HF- and NF- dominated frac hits are classified and studied. Combined with the correlation analysis method and the chart method, the main controlling factors affecting the two types of frac hits are determined, and the corresponding frac-hit prevention countermeasures are proposed. The research demonstrates that (1) the distribution and development of NFs are crucial to production after frac hits. NFs and HFs in the WY area cause 51% and 49%, respectively, of the frac hits. (2) The main controlling factors in NF-dominated frac hits are the approximation angle, fracture linear density, and horizontal stress difference, whereas they are net pressure in fractures, horizontal stress difference, and liquid strength in HF-dominated frac hits. Sensitivity analysis shows that the NF activation difficulty coefficient fluctuates between −35.1% and 47.6%, and the maximum hydraulic fracture length fluctuates between −43.5% and 25.29%. (3) The corresponding frac-hit prevention countermeasures are proposed for the two types of formation mechanisms from different approaches, including frac-hit risk assessment and path planning, production well pressurization and stress diversion, and infill-well fracturing parameter optimization. This paper not only provides a reference for exploring the formation mechanism of frac hits in fractured shale gas reservoirs but also a theoretical basis for the corresponding frac-hit prevention countermeasures.

Optimization of shale gas fracturing parameters based on artificial intelligence algorithm

Resource-rich shale gas plays a pivotal role in new energy types. The key to scientifically and efficiently developing shale gas fields is to clarify the main factors that affect the production of shale gas wells. In this paper, according to the shale gas reservoir characteristic of the Fuling marine Longmaxi Formation, a single-well geological model was established using the reservoir numerical simulation software CMG. Then, 10,000 different reservoir models were randomly generated for different formation physical parameters, completion parameters, and fracturing parameters using the Monte Carlo method, and these 10,000 models were simulated numerically. The machine learning model uses a dataset of 10,000 different geological, completion, and fracturing parameters as input and 10,000 production curves as output. Multiple machine learning regression methods were used to train and test the dataset, and the optimal method (GBDT algorithm) was selected, and the accuracy R2 of the test set of the GBDT prediction model is 0.96. A fracturing parameter optimization workflow was constructed by combining a production prediction model with a particle swarm optimizer (PSO). The process can quickly optimize the fracturing parameters and predict the production for each time by targeting the cumulative gas production under different geological conditions. The optimized parameters are Fracture Spacing, Fracture Width, Intrinsic Permeability, Fracture Half-length, Langmuir Pressure, and Langmuir Volume. The initial predicted cumulative gas production was 4.59 × 108 m3, which was optimized to 4.90 × 108 m3. The proposed PSO-GBDT proxy model can instantly predict the production of shale gas wells with considerable accuracy, reliability, and efficiency, which is a vital tool for optimizing fracture design. This investigation provides a solid foundation for predicting the production of unconventional gas reservoirs and for parameter optimization.

Post-frac evaluation of deep shale gas wells based on a new geology-engineering integrated workflow

The development of shale gas reservoir is now shifting focus from mid-shallow reservoirs to deep reservoirs in the southern Sichuan Basin. For such reservoirs with high temperature, pressure, and stress difference, along with multiple folds, faults, and complex fracture networks, improving the stimulation performance of shale gas wells is the ultimate challenge. This study presents a new geology-engineering integrated workflow coupling hydraulic fracture simulation and reservoir simulation together with artificial intelligence to perform post-frac evaluations. A two-step calibration workflow of fracturing and reservoir simulations generated an ensemble of representative models, and a confidence interval of estimated ultimate recovery forecast were obtained. Four deep shale gas wells with two different completion versions (version 1.0 and version 2.0) in Y101 study area were evaluated. Some of the key learnings include: (1) the ratio of stimulated rock volume and drained rock volume is quantified to 8%–25% for the four characterized deep shale gas wells; (2) the version 2.0 completion design is able to stimulate the near-well region more effectively than version 1.0; (3) this novel geology-engineering integrated workflow performed the first reliable, robust and quantifiable post-frac evaluation in the southern Sichuan Basin deep shale reservoir.

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%.

Influencing factors and prevention measures of casing deformation in deep shale gas wells in Luzhou block, southern Sichuan Basin, SW China

Based on structural distribution and fault characteristics of the Luzhou block, southern Sichuan Basin, as well as microseismic, well logging and in-situ stress data, the casing deformation behaviors of deep shale gas wells are summarized, and the casing deformation mechanism and influencing factors are identified. Then, the risk assessment chart of casing deformation is plotted, and the measures for preventing and controlling casing deformation are proposed. Fracturing-activated fault slip is a main factor causing the casing deformation in deep shale gas wells in the Luzhou block. In the working area, the approximate fracture angle is primarily 10°–50°, accounting for 65.34%, and the critical pore pressure increment for fault-activation is 6.05–9.71 MPa. The casing deformation caused by geological factors can be prevented/controlled by avoiding the faults at risk and deploying wells in areas with low value of stress factor. The casing deformation caused by engineering factors can be prevented/controlled by: (1) keeping wells avoid faults with risks of activation and slippage, or deploying wells in areas far from the faulting center if such avoidance is impossible; (2) optimizing the wellbore parameters, for example, adjusting the wellbore orientation to reduce the shear force on casing to a certain extent and thus mitigate the casing deformation; (3) optimizing the casing program to ensure that the curvature radius of the curved section of horizontal well is greater than 200 m while the drilling rate of high-quality reservoirs is not impaired; (4) optimizing the fracturing parameters, for example, increasing the evasive distance, lowering the single-operation pressure, and increasing the stage length, which can help effectively reduce the risk of casing deformation.

Proxy Model Forecasts Production of Shale Wells With Complex Fracture Networks

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 209635, “A Deep-Learning-Based Approach for Production Forecasting and Reservoir Evaluation for Shale Gas Wells With Complex Fracture Networks,” by Peng Dong, SPE, and Xinwei Liao, China University of Petroleum at Beijing. The paper has not been peer reviewed. _ The complete paper proposes a data-driven proxy model to effectively forecast the production of horizontal wells with complex fracture networks in shales. With a multilayer gated recurrent unit (GRU) cell, the proxy model is coupled with newly developed deep-learning methods, an attention mechanism (Att-GRU), skip connection, and cross-validation to deal with time-series-analysis (TSA) issues of multivariate operating and physical parameters. Results indicate that the Att-GRU method can forecast the production for shale gas wells with complex fracture networks accurately at a given time and with variable bottomhole pressure (BHP) while maintaining high calculation efficiency. Methodology The authors write that their main interest is to develop a physics-based data-driven model to speed up the simulation of complex fracture networks in shale reservoirs. Results show that the deep-learning model can faithfully recapitulate the variable BHP condition in all of its intricacies with multivariate physical input. In this section of the complete paper, the involved physical background and the corresponding governing equations are clarified. Then, the principle behind the Att-GRU for the problem of complex-fracture-network wells in shale reservoirs is explained. Data initialization and preprocessing and model structure are discussed. Because these sections are equation-intensive and are not suitable for this synopsis but are essential to the methodology explained in the paper, the reader is encouraged to review them in the complete text. Results and Discussions In this section of the complete paper, the physical data in the boundary element method (BEM) are used to train and test the Att-GRU model. The training procedure, test results, and parameters analysis are clarified. The computation burden of the data-driven Att-GRU is compared with the physical model.

Life-cycle deliquification techniques and their application for deep shale gas reservoirs

Deep shale gas resources in the Sichuan Basin have great potential, and this is a major area for future shale gas exploration and development. Deep shale gas wells face problems with liquid loading throughout the production cycle. Regarding deliquification techniques, it is necessary to consider the requirements of gas wells over the full life cycle, as well as the main form of artificial lift used at different stages, to achieve economically efficient development. This paper divides the life cycle of a deep shale gas well into two stages: early production and middle/late production. Pressure-control production is conducted in the early stage of production, whereas investigations on critical liquid-carrying models, the flow distribution in the wellbore, and the main form of artificial lift are conducted in the middle and late stages of production. A recommended scheme of deliquification techniques over the full life cycle has been developed to guide the development and enhancement of artificial lift methods in deep shale gas reservoirs. As of March 2022, in the PetroChina Southwest Oil & Gasfield Company managed-pressure production has been implemented in 14 wells in the early stage of deep shale gas production. In eight wells, plunger gas lift has been implemented in the middle and late stages of production. In seven wells, foam lift has been implemented. The abovementioned techniques are effective in increasing and stabilizing production and achieving deliquification in deep shale gas reservoirs.

Corrosion Mechanism of Typical Shale Gas Gathering and Transportation Pipelines in Southwest China

The shale gas surface gathering and transportation pipeline in southwest China has experienced serious internal corrosion, which affects the production of shale gas wells and has great potential safety hazards. To find out the corrosion type and corrosion mechanism, the corrosion analysis and mechanism research of gathering and transportation pipelines are carried out, including corrosion morphology observation, corrosion product analysis, fluid mechanics calculation, etc. The results show that the corrosion products of the gathering and transportation pipeline are mainly FeCO3 with high S content, and the corrosion type is sulfate-reducing bacteria (SRB) and CO2 corrosion. At the same time, the corrosion pits are mainly distributed on the approach stream side, which is closely related to the scouring effect of the medium flow in the vertical branch pipe on the wall surface of the tee. The corrosion weight loss test shows that the corrosion rate of sterile solution is significantly lower than that of bacterium solution, indicating that the presence of SRB significantly expedites the corrosion of materials.

Toxicity identification evaluation for hydraulic fracturing flowback and produced water during shale gas exploitation in China: Evidence from tissue residues and gene expression.

Hydraulic fracturing flowback and produced water (HF-FPW) from shale gas extraction processes is a highly complex medium with potential threats to the environment. Current research on ecological risks of FPW in China is limited, and the link between major components of FPW and their toxicological effects on freshwater organisms is largely unknown. By integrating chemical and biological analyses, toxicity identification evaluation (TIE) was used to reveal causality between toxicity and contaminants, potentially disentangling the complex toxicological nature of FPW. Here, FPW from different shale gas wells, treated FPW effluent, and a leachate from HF sludge were collected from southwest China, and TIE was applied to obtain a comprehensive toxicity evaluation in freshwater organisms. Our results showed that FPW from the same geographic zone could cause significantly different toxicity. Salinity, solid phase particulates, and organic contaminants were identified as the main contributors to the toxicity of FPW. In addition to water chemistry, internal alkanes, PAHs, and HF additives (e.g., biocides and surfactants) were quantified in exposed embryonic fish by target and non-target tissue analyses. The treated FPW failed to mitigate the toxicity associated with organic contaminants. Transcriptomic results illustrated that organic compounds induced toxicity pathways in FPW-exposed embryonic zebrafish. Similar zebrafish gene ontologies were affected between treated and untreated FPW, again confirming that sewage treatment did not effectively remove organic chemicals from FPW. Thus, zebrafish transcriptome analyses revealed organic toxicant-induced adverse outcome pathways and served as evidence for TIE confirmation in complex mixtures under data-poor scenarios.

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.

Failure Analysis of Casing in Shale Oil Wells under Multistage Fracturing Conditions

During the multistage fracturing in shale oil and gas wells with tieback and liner, one of the major challenges is the wellbore temperature variation due to the high-rate fracturing. In such a case, the axial shrinkage trend of the casing string could be caused due to the sudden drop in temperature, but the actual axial length of the casing string would not change due to the cement constraints. Therefore, this could lead to cementation damage between the casing and cement due to excessive load from the casing string. A wellbore seal that is out of control often leads to irreversible consequences, even well abandonment. In order to study the mechanism of casing deformation in shale oil and gas wells with tieback and liner quantitatively, in this paper, take LS1 well (a typical shale oil and gas well with tieback and liner, and casing deformation is caused) for example, the transient changes of temperature and pressure in the whole wellbore during multistage fracturing are studied. Moreover, the cementing strength test of the interface between casing and cement is also tested. Then, the testing results are carried out and extended to model the finite element (FE) model with the whole vertical section casing string with tieback and liner. The model is used to simulate the internal force changes under fracturing conditions with different stages of fracturing. Meanwhile, the casing deformation mechanism in LS1 well is analyzed and studied in detail. Our simulation results indicated the failure process and mechanism of cementation between casing and cement in shale oil and gas wells with tieback and liner. Our work can provide a detailed theoretical reference and a basis for field application.