bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimization Method of Hydraulic Fracturing Design for Horizontal Shale Gas Well Based on Artificial Neural Network and Genetic Algorithm
Authors: Luo Y. , Guo J. C. , Zeng F. H. , Lu C. , Wang R. , Guan B. , Ren Y. , Yuan C. M. , He L. , Zhou G. Q. , Wang J. G. , Liu Y. H. , Wang X. S. , Shan X. 
Published: September 2022

ABSTRACT:
Multistage hydraulic fracturing in horizontal well is the key means to realize efficient development of shale reservoir. Traditional fracturing optimization mainly applies single factor analysis or orthogonal test based on numerical simulation, which is time consuming and is difficult to obtain the global optimal solution. In this paper, an optimization method of hydraulic fracturing design for horizontal shale gas well based on artificial neural network (ANN) and genetic algorithm (GA) is proposed. On the basis of collecting geology, engineering, and production data of fractured horizontal wells, the main production influencing factors are obtained with recursive feature elimination and cross validation method, then a data-driven production prediction model is constructed based on ANN, and the GA is used to search the global optimal combination of fracturing parameters. With the data set of 162 fractured horizontal wells from a shale gas field in Sichuan Basin, an ANN production prediction model is trained and tested. The calculation efficiency is high, and the determination coefficient exceeds 0.8. Furthermore, an optimal fracturing parameters combination strategy is proposed for a new completed well in this area. This method can provide some guidance for production evaluation and hydraulic fracturing design of horizontal shale gas wells.

1. INTRODUCTION
Shale gas development mainly relies on horizontal well and staged fracturing, optimizing the fracturing strategy is critical to maximize well production and the ultimate recovery. The current fracturing optimization design mainly applies single factor analysis or orthogonal test methods to find the optimal horizontal well length, number of fractures, or fracture length, with the goal to maximize well production or net present value. However, limited by the search method and search interval, it is difficult to obtain the global optimal solution. What’s more, the optimization process is carried out with numerical simulator, involving complex and coupled fluid flow in matrix, natural fractures, artificial fractures and wellbore, so the calculation is time-consuming. Thanks to the increase of shale gas development efforts, data related to development and production are accumulating rapidly and continuously (Tan et al. 2017; Zhang et al. 2022). Therefore, extracting knowledge from the existing data, establishing a reliable and fast model to predict the well production, and then carrying out fracturing optimization with the combination of intelligent algorithm, is of practical interest for fracturing engineers.
Enhanced Rate of Penetration Prediction with Rock Drillability Constraints: A Machine Learning Approach
Authors: Fan Y. D. , Jin Y. , Pang H. W. , Wang S. G. 
Published: September 2022

ABSTRACT:
The rate of penetration (ROP) is directly related to the drilling cost. Accurate prediction of the ROP is of great significance to reduce the drilling cost. At present, there are two main types of methods for predicting ROP. One is based on physical mechanism analysis. However, due to many kinds of parameters affecting ROP, the prediction results are often very different from the actual ROP. The other is the data-driven prediction model of ROP. For the sample data with no obvious characteristics or "small sample" data, compared with the actual results, the prediction results of data-driven model have large errors. To solve the above problems, a new machine learning ROP prediction model based on physical mechanism constraints is proposed in this paper. Based on the data of 4 wells in X block of T oil field, the random forest model is selected from the three machine models including support vector regression, random forest, and regression tree, and the rock drillability constraint is added to predict the ROP. The prediction results that do not meet the rock drillability constraints are optimized to reduce the prediction error. The results show that the random forest model with constraints has the best performance, and the prediction error is reduced from 14.52% to 11.27%.

1. INTRODUCTION
ROP prediction methods can be divided into two categories: one is the physical model based on parameter relationships, and the other is the machine learning model based on big data (Gan, 2019). Maurer (1962) proposed a model for predicting the ROP of rolling cutting tooth bit based on WOB, formation drillability, rock compressive strength, and bit size. Bingham (1965) introduced the weight index based on Maurer’s model to predict the ROP. Bourgoyne and Young (1974) considered the formation strength, formation depth, compactness, bottom hole differential pressure, bit size, bit weight, bit wear, string ROP, and bit hydraulics, and established a multiple regression ROP prediction model. Warren (1987) gave the prediction model of cone bit penetration rate based on rock compressive strength, string rate of penetration, torque, and bit size. Hareland et al. (2010) established the prediction model of ROP by considering the physical number of insertions in contact with rock, the physical number of insertions through rock, the cutting angle of formation, and the ultimate strength of rock. The ROP prediction model based on the mechanism model takes into account the limited parameters affecting the ROP, and the mechanism relationship between each parameter and the ROP is mostly given through experimental assumptions. Therefore, the accuracy of predicting the ROP based on the physical model is low.
Numerical Study on the Effect of Localized Fluid Pressurization on Shear and Hydraulic Behavior of a Natural Fracture in Granite
Authors: Du M. , Zhang F. , Liu F. , Zhuang L. 
Published: September 2022

ABSTRACT:
Mechanical and hydraulic properties of fractures are strongly affected by the exploitation of enhanced geothermal system (EGS) and unconventional reservoirs. This study attempts to reveal the evolution of shearing properties and fluid pressure heterogeneity of natural fractures, possibly caused by mud loss during drilling and hydraulic stimulation. A series of triaxial shear-flow and injection-driven shear numerical simulations were carried out using a coupled hydro-mechanical pore network method (PNM) in DEM. Fracture surface profiles were generated according to the X-ray computed tomography scanning data of open and closed joints of rock cores retrieved from a 4.2-km-deep well at the Pohang EGS site. We developed an algorithm to update the orientations of joint contacts automatically and overcome the mismatch between joint roughness and contact direction especially at large shear displacement. A refreshing fluid grids approach based on the PNM is modified by Delaunay triangulation and Kriging interpolation. The results indicate that injection has caused pressure heterogeneity in the pressurized area. Localized shear rupture could occur in the area with highly concentrated pore pressure. These characteristics also emphasize the significant cause of fluid pressure heterogeneity in rupture propagation in a fracture, likely resulting in unstable slip of critically stressed preexisting faults after small fluid pressure perturbations.

1. INTRODUCTION
Mechanical and hydraulic properties of fractures are strongly affected by the exploitation of enhanced geothermal system when hydraulic stimulation is utilized to enhance the permeability of hot dry rock (Rathnaweera et al., 2020). Anthropogenic fluid injections into rock crust can generate seismicity (Guglielmi et al., 2015; An et al., 2020), which brings more challenges to exploit this clean energy. For instance, an Mw 5.5 earthquake, one of the most damaging events in South Korea, was induced by hydraulic stimulation in 4.2-km-deep granodiorite. After 2 years’ hydraulic stimulation, highly localized fluid pressurization and perturbation induced by hydraulic stimulation destabilized and activated the fault where the main shock happened (Kim et al., 2018; Gorigli et al., 2018). Many injection-driven shear tests experiments and numerical computation have been carried out to investigate injection-induced fracture instability. Ji et al. (2020, 2021) carried out triaxial shear-flow experimental tests and COMSOL numerical simulations to recover fluid pressure heterogeneity on rock fractures. Fluid pressure heterogeneity on a rock fracture may induce localized shear rupture and propagates to activate the entire fracture. Analytical models that could describe the decrease of frictional strength of a rock fracture and predict potential seismic events have been proposed (Wei et al., 2021; Ji et al., 2021).
Contribution of the Water Weakening Effect to Plastic Strain: Case Studies from Danish North Sea Chalk Fields
Authors: Amour F. , Hajiabadi M. R. , Nick H. M. 
Published: September 2022

ABSTRACT:
The experimental studies highlighting the strength weakening of chalk when water replaces oil in pore space have incited geomodellers to systematically solve for the effect of water saturation on chalk strength at each simulation step to estimate reservoir compaction. The present study demonstrates quantitatively for the first time the important role played by the water weakening effect on the deformation of several producing fields in the Danish North Sea. Although non-negligible, the water weakening effect in the studied fields is caused by the initial water saturation of chalk rather than by its changes through time. Representative of numerous Danish North Sea reservoirs, the outcome of this study suggests that a preliminary assessment of the potential magnitude of the water weakening effect during production should be first performed prior to compaction simulation. If considered negligible, the adjustment of the rock strength according to the saturation conditions at each simulation step can be ignored, thereby reducing the computing time required to perform coupled geomechanical and fluid flow modelling.

1. INTRODUCTION
Waterflooding of reservoir is a common stimulation technique to enhance the recovery factor of hydrocarbon fields within chalk intervals of the North Sea. The resulting increase in water saturation in pore space leads to a softening of the mechanical properties of the rock, such as the pore collapse stress, a process referred to as the water weakening effect. This process has been extensively studied in laboratory during the last three decades and the underlying mechanisms are still under debate. Nevertheless, the adsorption of ions and water molecules from the aqueous phase at the surface of calcite particles that involves an additional repulsive force between grains favouring grain -to-grain slippage is commonly pointed out as the main mechanisms. Laboratory studies have shown that the pore collapse stress of oil-saturated outcrop samples is consistently reduced by 50-60% when saturated with water, thereby causing additional strain. Triaxial tests conducted on core samples from the North Sea have also demonstrated the dependency of the pore collapse stress to water saturation.
A Case Study on Longwall-Induced Rockmass Permeability Under Medium Cover: Potential Gas Inflow Implications
Authors: Khademian Z. , Ajayi K. M. , Kim B. H. 
Published: September 2022

ABSTRACT:
In the Northern Appalachian Basin of the United States, most of the production wells in shale gas reservoirs intersect with a bedded sequence of minable coal layers. The gas wells are often positioned in the coal mine abutment pillars for protection, but longwall-induced stresses may lead to excessive deformation in the gas well casing and potentially leak high-pressure gas to the mining area. Quantitative analyses of the potential gas inflow need an understanding of the rockmass permeability evolution during longwall mining. For this study, a medium-cover (198-m deep) mining site in eastern West Virginia was selected to calculate longwall mining-induced permeability changes. A model in 3DEC numerical modeling code was constructed using the Discrete Fracture Network (DFN) technique to explicitly create fracture systems in the model and calculate fracture apertures under longwall-induced stress and deformations. The calculated fracture apertures are used in a fracture flow code (FFC) to predict the volumetric gas inflow to the mine in the case of a hypothetical breach in a gas well casing. The potential breach location was identified using a 60-arm caliper survey in a test well in abutment pillar, showing that the maximum horizontal displacement occurs 51 m below the surface. The results of FFC simulation for the breach in this location shows that in 100 different DFN realizations, there is no sign of gas reaching the mine workings.

1. INTRODUCTION
Due to the specific geologic conditions in the Northern Appalachian Basin of the United States, many minable coal seams are located above shale gas reservoirs. Shale gas operation wells can intersect with future or active longwall mines, but guidelines must be followed to ensure the safety of both operations (PADEP 2018). If the longwall-induced deformation of rockmass surrounding the gas wells leads to excessive deformation and stress in well casings, the high-pressure, explosive gas may reach mine workings and overwhelm the mine ventilation systems. In order to protect gas wells from longwall-induced deformations, the wells are usually designed to be installed within the abutment pillars between longwall panels. However, for developing safety guidelines, it is important to quantify the amount of gas that would travel to the mine workings in case of well damage.
Research of Casing Deformation Problem Based on U-Tube Effect During Cementing Injection Stage
Authors: Liu Jinlu , Li Jun , Li Hui , Liu Gonghui , Li Yizheng , Wang Shiguo , Yang Hongwei 
Published: September 2022

ABSTRACT:
During the cementing injection stage, due to the existence of U-tube effect, the casing deformation and even fracture occur, which seriously threatens the wellbore safety. In this paper, according to the critical moment, the cementing injection stage is divided into the different process. Based on the equations of friction resistance, a calculation method of vacuum section is proposed. Through the analysis of the casing force, a mathematical model for simulating casing deformation and calculating parameters such as displacement is established. The model is validated with data from Well X in the South China Sea, and the simulated results have high reliability, within 10% of the measured values. The results were analyzed and the following conclusions were drawn: when the U-tube effect occurs in the wellbore, the outflow displacement is not equal to the injection displacement; when the vacuum sect ion is generated, the pump pressure is 0; the injection displacement is the most influential factor on casing deformation, and the suitable displacement is 12-14L/s, where the casing deformation is small and fatigue failure does not occur.

1. INTRODUCTION
During past few decades, drilling gradually to the deep well, ultra-deep well development. In the process of development, scholars have encountered many problems, one of which is casing deformation during cementing. Casing deformation is a problem throughout the cementing process, from the beginning of the cementing injection stage to several decades after the waiting setting (Ping et al., 2021; Gqha et al., 2021; Xi et al., 2020). At present, the problem of wellbore integrity after the waiting setting stage has become increasingly mature (Jiang et al., 2020; Yan et al., 2019; Li et al., 2019), but the problem of casing force and deformation during injection stage have not been unified
In cementing injection stage, a U-tube effect occurs in the wellbore because the cement slurry is denser than the drilling fluid. The U-tube effect will redistribute the wellbore pressure field and velocity field, and then affect the force and deformation of casing. At present, scholars have formed a certain understanding of the U-tube effect. A mathematical model and simulation simulator have been established (Beirute et al., 1984; Sauer et al., 1987) to predict the flow rate, bottomhole pressure and other parameters during the U-tube effect in vertical Wells. For directional wells, a computational analysis model has been proposed (Liu et al., 1995) that takes into account the difference between vertical and deviated sections. Corresponding computer software has also been developed (Li et al., 2006), which can be used to analyze the velocity field and pressure field of fluid under different conditions.
Stress Interference Between Fractures of Alternating Fracturing of Horizontal Wells
Authors: Wang Wenrui , Zhang Guangqing , Zhao Chunyang , Shen Liji , Chen Houze , Zhang Tongwu 
Published: September 2022

ABSTRACT:
The fracturing sequence could affect the stress disturbance, which is main factor of the formation of a complex fracture network. The characteristics of inter-fracture interference under different fracturing sequences needs to be studied. We carried out the hydraulic fracturing experiment with multiple fracture points under three-dimensional stress conditions. A numerical model of hydraulic fracturing was constructed based on the extended finite element method, which was used to study the effect of fracturing methods under the conditions of different fracture spacing and initial horizontal stress. The results show that :(1) A lot of branch fractures are generated near the main fracture due to subsequent fracture cyclic compression, being perpendicular to the primary fracture. Meanwhile, the stress interference could lead to the activation and coalescence of natural micro-fractures. (2) When the fracture spacing exceeds 25m, and the original horizontal stress difference exceeds 6 MPa, the complex fracture network is more easily formed by alternate fracturing. (3) The average interference pressure will increase with the initial horizontal stress difference, while its rate is less than the increase of initial horizontal stress difference. The higher original horizontal stress would activate less natural micro-fractures. (4) The average interference stress generated by alternating fracturing is higher than that generated by sequential fracturing, ranging from 0.70 MPa to 1.90 MPa. The alternating fracturing is more benefit to form complex network of fractures, with the increase of the initial horizontal stress difference and fracture spacing, comparing with sequential fracturing. This research could guild the optimization of hydraulic fracturing in field application.

1. INTRODUCTION
Horizontal well-staged fracturing technology is crucial for shale reservoirs’ stimulation. However, the fracturing process deflected the hydraulic fractures, and the shape is uncontrollable(Wu and Olson 2015; Wu et al. 2012). Research shows that this phenomenon is that the original fractures will produce stress interference, resulting in uncontrollable subsequent fracture shapes. The shorter the fracture spacing is, the more significant this phenomenon is. However, if a larger fracture spacing is set, the fracturing blind zone will lead to the fracturing effect being unsatisfactory(Wenrui et al. 2018; Gang et al. 2020). Alternate fracturing achieves the result of using stress interference by changing the fracturing sequence, producing a complex and morphologically controllable fracture network. Studying the effect of alternating fracturing stress interference can provide a theoretical basis for better utilization of stress interference.
Dry and Fluid Permeated Hydraulic Fractures and Their Geophysical Signatures in Granitic Rocks
Authors: Butt Awais , Hedayat Ahmadreza , Moradian Omid 
Published: September 2022

ABSTRACT:
Passive seismic monitoring can assist in mapping the generated hydraulic fracture network and determining the fracture source mechanisms during fluid stimulation operations. While this is the most applied technique that provides critical information, it has certain limitations which can influence its capability to estimate the efficiency of the stimulation operation. This study involved the HF of true-triaxially loaded low permeability Barre granite cubes with combined real-time active (ultrasonic) and passive (acoustic emission) monitoring using high viscosity gear oil with the injection rate of 0.1 ml/min. After data filtering, acoustic emission (AE) monitoring successfully mapped the fluid induced damage and its evolution in the brittle rocks mass. Different attributes of the continuous ultrasonic signals (velocity and energy) were analyzed in combination with the detected micro-seismic events which highlighted the difference between fluid permeated and non-fluid permeated fracturing along with various fracturing processes induced due to pressurized fluid injection. These results indicate that utilizing different acoustic techniques together has the potential to better characterize the fluid induced damage in brittle rocks.

1. INTRODUCTION
While hydraulic fracturing (HF) is a widely employed technique, it is difficult to predict the HF growth and the underlying mechanisms (Zhuang and Zang, 2021). AE or seismic monitoring at the laboratory or field scales, respectively, is a passive acoustic monitoring technique that has been the most effective and robust technique available for monitoring the fluid induced damage in brittle rocks (Stanchits et al., 2015). This method can record real-time micro-seismic data, which can be utilized not only to map the generated HF but can also be processed to determine the underlying source mechanisms in both field and laboratory scales (Hampton et al., 2018). This detailed analysis of the detected micro-seismicity can greatly assist in determining the efficiency of the stimulation operation (Maxwell, 2014). However, detected micro-seismicity only represents one component of the geo-mechanical response to HF. Micro-seismicity can occur both due to the localized fluid pressure and stress perturbations causing inelastic micro-damage surrounding the propagating fracture (Maxwell et al., 2015). Micro-seismicity will be generated surrounding the injection borehole, even if the fluid is prohibited from entering the surrounding rock, for example through sleeve fracturing (Ishida et al, 2004). Therefore, it may be difficult to distinguish between the fluid permeated fracturing, and non-fluid permeated fracturing. This is a crucial piece of information required for an accurate estimation of stimulated reservoir volume and efficient design of the deep underground stimulation operation.