Effect of Fracture Parameters on Desorption Properties of Shales

2013 ◽  
Vol 397-400 ◽  
pp. 252-256
Author(s):  
Kun Kun Fan ◽  
Ren Yuan Sun ◽  
Zi Chao Ma ◽  
Yun Fei Zhang ◽  
Yan Wei ◽  
...  
Keyword(s):  
Shale Gas ◽  
Horizontal Well ◽  
Experimental System ◽  
Desorption Rate ◽  
Desorption Process ◽  
Pressure Drops ◽  
Equilibrium Time ◽  
System Pressure ◽  
Shale Sample ◽  
Half Length

Horizontal well and hydraulic fracturing are the main technologies for shale gas development. The desorption properties of shales are very important data for shale gas development. In order to simulate the desorption process in shales with horizontal well and fractures, a new method for shale sample preparation and a new experimental system for the evaluation were developed. The effect of the number and half-length of fractures on the desorption rate and the desorption equilibrium time were measured when the system pressure drops from 9.2MPa to 7MPa. Experiments show that the initial desorption rate increases and the equilibrium time decreases with the increase of the number and half-length of fractures. Within the scope of the experiments, the number of fractures is more important than the half-length of fractures for the desorption rate.

scholarly journals Study on Desorption Experiment and Desorption Model of Deep Shale Gas Containing Water

2021 ◽  
Vol 2021 ◽  
pp. 1-10
Author(s):  
Zuping Xiang ◽  
Yangyang Ding ◽  
Xiang Ao ◽  
Zehua Cheng ◽  
Qianhua Xiao ◽  
...  
Keyword(s):  
Water Content ◽  
Shale Gas ◽  
Desorption Process ◽  
Pressure Drops ◽  
Adsorbed Gas ◽  
Desorption Hysteresis ◽  
The Impact ◽  
Adsorption Curve ◽  
Desorption Model ◽  
Water Contents

In this work, the methane desorption isothermal curves at different water contents on deep sampled from Western Chongqing of China were measured at pressures up to 65 MPa and at 130°C by the volumetric method. In the first instance, the desorption increases with the decrease of pressure, the adsorbed gas desorbs slightly with decreasing pressures from 65 to 30 MPa. When the pressure drops to 30–20 MPa, the desorption rate increases rapidly with the decrease of pressure and the desorption curve begins to separate from the adsorption curve, resulting in desorption hysteresis. At last, when the pressure is lower than 20 MPa, the desorption increases almost linearly with the further decrease of pressure, but eventually there will be some adsorbed gas which cannot be desorbed to form residual adsorbed gas. After that, the isotherm desorption data of CH4 was fitted using the improved desorption model. The fitting results showed that the improved desorption model can be used to describe the desorption process of deep shale gas containing water and has a strong applicability. In addition, the critical desorption pressure increases with increasing water content. When the water content is lower than 1%, the effect of the water content on the desorption of deep shale gas increases rapidly with increasing water content, as well as when the water content is greater than 1%, the impact changes slowly.

scholarly journals Parameter Optimization of Segmental Multicluster Fractured Horizontal Wells in Extremely Rich Gas Condensate Shale Reservoirs

2021 ◽  
Vol 9 ◽  
Author(s):  
Wei Zhipeng ◽  
Wang Jinwei ◽  
Liu Rumin ◽  
Wang Tao ◽  
Han Guannan
Keyword(s):  
Shale Gas ◽  
Horizontal Well ◽  
Production Capacity ◽  
Horizontal Wells ◽  
Distribution Patterns ◽  
Gas Condensate ◽  
Fracture Permeability ◽  
Mesh Density ◽  
Fractured Horizontal Wells ◽  
Half Length

For economic and efficient development of extremely high-condensate shale gas reservoirs, a numerical model of segmental multicluster fractured horizontal well was established considering the effect of condensate and desorption, and the optimization of fracturing segments, fracturing clusters, half-length of main fracture, fracture permeability, fracture mesh density, and fracture distribution patterns were studied. It is indicated that the horizontal well whose design length is 2,700 m performs best when it has 43 fracturing segments with three clusters in each segment and the fracture permeability is 300 mD. The production capacity of horizontal wells is positively linearly correlated with the half-length of fractures. Increasing fracture half-length would be an effective way to produce condensate oil near wellbore. An effective fractured area can be constructed to remarkably improve productivity when the half-length of the fracture is 50 m and the number of secondary fractures is four in each segment. On the basis of reasonable fracture parameters, the staggered type distribution pattern is beneficial to the efficient development of shale gas-condensate reservoirs because of its large reconstruction volume, far pressure wave, small fracture interference, and small precipitation range of condensate.

scholarly journals A Novel Shale Gas Production Prediction Model Based on Machine Learning and Its Application in Optimization of Multistage Fractured Horizontal Wells

2021 ◽  
Vol 9 ◽  
Author(s):  
Huijun Wang ◽  
Lu Qiao ◽  
Shuangfang Lu ◽  
Fangwen Chen ◽  
Zhixiong Fang ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Simulation Model ◽  
Shale Gas ◽  
Horizontal Well ◽  
Gas Production ◽  
Production Model ◽  
Support Vector ◽  
Gas Production Prediction ◽  
Half Length ◽  
Production Prediction

Shale gas production prediction and horizontal well parameter optimization are significant for shale gas development. However, conventional reservoir numerical simulation requires extensive resources in terms of labor, time, and computations, and so the optimization problem still remains a challenge. Therefore, we propose, for the first time, a new gas production prediction methodology based on Gaussian Process Regression (GPR) and Convolution Neural Network (CNN) to complement the numerical simulation model and achieve rapid optimization. Specifically, through sensitivity analysis, porosity, permeability, fracture half-length, and horizontal well length were selected as influencing factors. Second, the n-factorial experimental design was applied to design the initial experiment and the dataset was constructed by combining the simulation results with the case parameters. Subsequently, the gas production model was built by GPR, CNN, and SVM based on the dataset. Finally, the optimal model was combined with the optimization algorithm to maximize the Net Present Value (NPV) and obtain the optimal fracture half-length and horizontal well length. Experimental results demonstrated the GPR model had prominent modeling capabilities compared with CNN and Support Vector Machine (SVM) and achieved the satisfactory prediction performance. The fracture half-length and well length optimized by the GPR model and reservoir numerical simulation model converged to almost the same values. Compared with the field reference case, the optimized NPV increased by US$ 7.43 million. Additionally, the time required to optimize the GPR model was 1/720 of that of numerical simulation. This work enriches the knowledge of shale gas development technology and lays the foundation for realizing the scale-benefit development for shale gas, so as to realize the integration of geological engineering.

scholarly journals Investigation of the Main Factors During Shale-gas Production Using Grey Relational Analysis

2016 ◽  
Vol 9 (1) ◽  
pp. 207-215 ◽  
Author(s):  
Hongling Zhang ◽  
Jing Wang ◽  
Haiyong Zhang
Keyword(s):  
Shale Gas ◽  
Gas Production ◽  
Gas Reservoirs ◽  
Fracture Conductivity ◽  
Matrix Permeability ◽  
Shale Gas Reservoirs ◽  
Main Factors ◽  
Grey Relational ◽  
The Impact ◽  
Half Length

Shale gas is one of the primary types of unconventional reservoirs to be exploited in search for long-lasting resources. Production from shale gas reservoirs requires horizontal drilling with hydraulic fracturing to achieve the most economic production. However, plenty of parameters (e.g., fracture conductivity, fracture spacing, half-length, matrix permeability, and porosity,etc) have high uncertainty that may cause unexpected high cost. Therefore, to develop an efficient and practical method for quantifying uncertainty and optimizing shale-gas production is highly desirable. This paper focuses on analyzing the main factors during gas production, including petro-physical parameters, hydraulic fracture parameters, and work conditions on shale-gas production performances. Firstly, numerous key parameters of shale-gas production from the fourteen best-known shale gas reservoirs in the United States are selected through the correlation analysis. Secondly, a grey relational grade method is used to quantitatively estimate the potential of developing target shale gas reservoirs as well as the impact ranking of these factors. Analyses on production data of many shale-gas reservoirs indicate that the recovery efficiencies are highly correlated with the major parameters predicted by the new method. Among all main factors, the impact ranking of major factors, from more important to less important, is matrix permeability, fracture conductivity, fracture density of hydraulic fracturing, reservoir pressure, total organic content (TOC), fracture half-length, adsorbed gas, reservoir thickness, reservoir depth, and clay content. This work can provide significant insights into quantifying the evaluation of the development potential of shale gas reservoirs, the influence degree of main factors, and optimization of shale gas production.

Evaluating the Performance of Horizontal Multi-Frac Wells in a Depleted Gas Condensate Reservoir in Sultanate of Oman

2022 ◽  
Author(s):  
Josef R. Shaoul ◽  
Jason Park ◽  
Andrew Boucher ◽  
Inna Tkachuk ◽  
Cornelis Veeken ◽  
...  
Keyword(s):  
Horizontal Well ◽  
Horizontal Wells ◽  
Gas Condensate ◽  
Integrated Analysis ◽  
Single Fracture ◽  
Reservoir Pressure ◽  
Well Test ◽  
Vertical Wells ◽  
Fracture Conductivity ◽  
Half Length

Abstract The Saih Rawl gas condensate field has been producing for 20 years from multiple fractured vertical wells covering a very thick gross interval with varying reservoir permeability. After many years of production, the remaining reserves are mainly in the lowest permeability upper units. A pilot program using horizontal multi-frac wells was started in 2015, and five wells were drilled, stimulated and tested over a four-year period. The number of stages per horizontal well ranged from 6 to 14, but in all cases production was much less than expected based on the number of stages and the production from offset vertical wells producing from the same reservoir units with a single fracture. The scope of this paper is to describe the work that was performed to understand the reason for the lower than expected performance of the horizontal wells, how to improve the performance, and the implementation of those ideas in two additional horizontal wells completed in 2020. The study workflow was to perform an integrated analysis of fracturing, production and well test data, in order to history match all available data with a consistent reservoir description (permeability and fracture properties). Fracturing data included diagnostic injections (breakdown, step-rate test and minifrac) and main fracture treatments, where net pressure matching was performed. After closure analysis (ACA) was not possible in most cases due to low reservoir pressure and absence of downhole gauges. Post-fracture well test and production matching was performed using 3D reservoir simulation models including local grid refinement to capture fracture dimensions and conductivity. Based on simulation results, the effective propped fracture half-length seen in the post-frac production was extremely small, on the order of tens of meters, in some of the wells. In other wells, the effective fracture half-length was consistent with the created propped half-length, but the fracture conductivity was extremely small (finite conductivity fracture). The problems with the propped fractures appear to be related to a combination of poor proppant pack cleanup, low proppant concentration and small proppant diameter, compounded by low reservoir pressure which has a negative impact on proppant regained permeability after fracturing with crosslinked gel. Key conclusions from this study are that 1) using the same fracture design in a horizontal well with transverse fractures will not give the same result as in a vertical well in the same reservoir, 2) the effect of depletion on proppant pack cleanup in high temperature tight gas reservoirs appears to be very strong, requiring an adjustment in fracture design and proppant selection to achieve reasonable fracture conductivity, and 3) achieving sufficient effective propped length and height is key to economic production.

Investigation of the Factors Influencing the Flowback Ratio in Shale Gas Reservoirs: A Study Based on Experimental Observations and Numerical Simulations

2021 ◽  
Vol 143 (11) ◽  
Author(s):  
Lin Hun ◽  
Zhou Xiang ◽  
Chen Yulong ◽  
Yang Bing ◽  
Song Xixiang ◽  
...  
Keyword(s):  
Numerical Simulations ◽  
Capillary Pressure ◽  
Influencing Factors ◽  
Shale Gas ◽  
Water Distribution ◽  
Pressure Curve ◽  
Gas Reservoirs ◽  
Desorption Process ◽  
Fluid Saturation ◽  
Shale Gas Reservoirs

Abstract The flowback behavior of hydraulic fractured horizontal well in shale gas reservoir is relatively different from that of conventional reservoirs. Therefore, it is necessary to investigate the relationship between the potential influencing factors and the flowback behavior in shale gas reservoirs. This study is based on experimental observations and numerical simulations. In the experiments, the flowback process was simulated through a gas displacement experiment, and the cores were scanned simultaneously to obtain the water distribution. Then, the water migration and retention mechanisms were investigated to determine the flowback behavior. For the numerical simulations, a multi-porosity model was established. The mathematical model accounted for the capillary pressure term. By matching the fluid saturation-front curves of the experimental and simulation results, a fitted capillary pressure curve, which reflects the multiple mechanisms controlling flowback, was obtained. Based on the established model and fitted capillary pressure, the flowback behavior and relevant influencing factors of the shale gas were investigated. The results show that the flowback ratio is inversely proportional to the clay content of the shale. A high salinity fracturing fluid or a surfactant solution can increase the flowback ratio. In addition, the injection pressure is proportional to the flowback ratio, while the matrix permeability and the flowback ratio have an inverse relationship. The adsorption–desorption process of gas has no significant effect on the flowback ratio. This study aims to provide a new method for analyzing the flowback performance of shale gas using a combination of experimental and numerical simulation methods.

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