scholarly journals An analytical model for describing sequential initiation and simultaneous propagation of multiple fractures in hydraulic fracturing shale oil/gas formations

2019 ◽  
Vol 7 (5) ◽  
pp. 1514-1526 ◽  
Author(s):  
Dong Xiao ◽  
Boyun Guo ◽  
Xiaohui Zhang
Keyword(s):  
Hydraulic Fracturing ◽  
Analytical Model ◽  
Shale Oil ◽  
Multiple Fractures ◽  
Oil Gas

Use of Mathematical Model to Predict the Maximum Permissible Stage Injection Time for Mitigating Frac-Driven Interactions in Hydraulic-Fracturing Shale Gas/Oil Wells

2020 ◽  
Vol 143 (8) ◽  
Author(s):  
Nan Zhang ◽  
Boyun Guo
Keyword(s):  
Hydraulic Fracturing ◽  
Analytical Model ◽  
Shale Gas ◽  
General Model ◽  
High Rate ◽  
Fluid Injection ◽  
Injection Time ◽  
Gas Oil ◽  
Fracturing Fluid ◽  
Multiple Fractures

Abstract Frac-driven interactions (FDIs) often lead to sharp decline in gas and oil production rates of wells in shale gas/oil reservoirs. How to minimize the FDI is an open problem in the oil and gas industry. Xiao et al.’s (2019, “An Analytical Model for Describing Sequential Initiation and Simultaneous Propagation of Multiple Fractures in Hydraulic Fracturing Shale Oil/Gas Formations,” Energy Sci Eng., 7(5), pp. 1514–1526.) analytical model for two-fracture systems was extended in this study to obtain a general model for handling multiple fractures. The general model was used to identify engineering factors affecting the maximum permissible stage fluid injection time for minimizing FDI. On the basis of model results obtained, we found that increasing fluid injection rate can create more short fractures and thus increase the maximum permissible stage injection time before FDI occurs. Use of dilatant type of fracturing fluid (n > 1) can reduce the growth of long fractures, promote the creation of more short fractures, and thus increase the maximum permissible stage injection time before FDI occurs. It is also expected that injecting dilatant type of fracturing fluid at high rate will allow for longer injection time and thus larger injection volume, resulting in larger stimulated reservoir volume (SRV) with higher fracture intensity and thus higher well productivity and hydrocarbon recovery factor.

scholarly journals Modeling Simultaneous Multiple Fracturing Using the Combined Finite-Discrete Element Method

Geofluids ◽  
2018 ◽  
Vol 2018 ◽  
pp. 1-20 ◽  
Author(s):  
Quansheng Liu ◽  
Lei Sun ◽  
Pingli Liu ◽  
Lei Chen
Keyword(s):  
Hydraulic Fracturing ◽  
Solid Phase ◽  
Horizontal Wells ◽  
In Situ Stress ◽  
Gas Production ◽  
Hydraulic Fractures ◽  
Multiple Fractures ◽  
Fracture Geometry ◽  
Stress Shadow ◽  
Oil Gas

Simultaneous multiple fracturing is a key technology to facilitate the production of shale oil/gas. When multiple hydraulic fractures propagate simultaneously, there is an interaction effect among these propagating hydraulic fractures, known as the stress-shadow effect, which has a significant impact on the fracture geometry. Understanding and controlling the propagation of simultaneous multiple hydraulic fractures and the interaction effects between multiple fractures are critical to optimizing oil/gas production. In this paper, the FDEM simulator and a fluid simulator are linked, named FDEM-Fluid, to handle hydromechanical-fracture coupling problems and investigate the simultaneous multiple hydraulic fracturing mechanism. The fractures propagation and the deformation of solid phase are solved by FDEM; meanwhile the fluid flow in the fractures is modeled using the principle of parallel-plate flow model. Several tests are carried out to validate the application of FDEM-Fluid in hydraulic fracturing simulation. Then, this FDEM-Fluid is used to investigate simultaneous multiple fractures treatment. Fractures repel each other when multiple fractures propagate from a single horizontal well, while the nearby fractures in different horizontal wells attract each other when multiple fractures propagate from multiple parallel horizontal wells. The in situ stress also has a significant impact on the fracture geometry.

AN ANALYTICAL MODEL OF A NON-STATIONARY TEMPERATURE FIELD IN A RESERVOIR WITH A HYDRAULIC FRACTURING

2021 ◽  
Vol 7 (2) ◽  
pp. 75-94
Author(s):  
Ramil F. SHARAFUTDINOV ◽  
Filyus F. Davletshin
Keyword(s):  
Temperature Field ◽  
Hydraulic Fracturing ◽  
Analytical Model ◽  
Oil Recovery ◽  
Temperature Anomaly ◽  
Nonstationary Temperature ◽  
Initial Moment ◽  
Positive Temperature ◽  
Fluid Filtration ◽  
Stage Of Development

At the present stage of development of the oil and gas industry, considerable attention is paid to methods of increasing oil recovery of productive reservoirs. One of the most popular methods of intensifying oil production today is hydraulic fracturing. The efficiency and success of hydraulic fracturing largely depends on the parameters of the formed fracture; in this regard, the development of methods for evaluating the parameters of hydraulic fracturing fractures is an urgent task. Non-stationary thermometry is a promising area for monitoring the quality of hydraulic fracturing. To date, thermometry is used to localize the locations of multiple fractures in horizontal wells. In this paper, we study the application of non-stationary thermometry for estimating the parameters of a vertical hydraulic fracturing fracture. An analytical model of non-isothermal single-phase fluid filtration in a reservoir with a vertical fracture is developed. To calculate the temperature field in the formation and the fracture, the convective heat transfer equation is used, taking into account the thermodynamic effects (Joule — Thomson and adibatic), for the fracture, the heat and mass transfer between the fracture and the formation area is also taken into account. To assess the correctness of the model, the analytical solution is compared with the results of numerical modeling in the Ansys Fluent software package. The nonstationary temperature field is calculated for the constant sampling mode. It is established that at the initial moment of time after the well start-up, a negative temperature anomaly is formed due to the adiabatic effect, the value of which increases with a decrease in the fracture width. Over time, the temperature of the fluid flowing into the well increases due to the Joule — Thomson effect, and the value of the positive temperature anomaly increases as the width and permeability of the fracture decreases due to an increase in the pressure gradient in it. The developed analytical model can be used to solve inverse problems for estimating hydraulic fracturing parameters based on non-stationary temperature measurements in the wellbore of producing wells.

scholarly journals Mechanisms and capacity of high-pressure soaking after hydraulic fracturing in tight/shale oil reservoirs

2020 ◽  
Author(s):  
Jing Wang ◽  
Hui-Qing Liu ◽  
Gen-Bao Qian ◽  
Yong-Can Peng
Keyword(s):  
High Pressure ◽  
Hydraulic Fracturing ◽  
Specific Surface ◽  
Surface Area ◽  
Oil Reservoirs ◽  
Shale Oil ◽  
Oil Viscosity ◽  
Soaking Time ◽  
Matrix Permeability ◽  
Shale Oil Reservoirs

Abstract Huff-n-puff by water has been conducted to enhance oil recovery after hydraulic fracturing in tight/shale oil reservoirs. However, the mechanisms and capacity are still unclear, which significantly limits the application of this technique. In order to figure out the mechanisms, the whole process of pressurizing, high-pressure soaking, and depressurizing was firstly discussed, and a mechanistic model was established. Subsequently, the simulation model was verified and employed to investigate the significances of high-pressure soaking, the contributions of different mechanisms, and the sensitivity analysis in different scenarios. The results show that high-pressure soaking plays an essential role in oil production by both imbibition and elasticity after hydraulic fracturing. The contribution of imbibition increases as the increase in bottom hole pressure (BHP), interfacial tension, and specific surface area, but slightly decreases as the oil viscosity increases. In addition, it first decreases and then slightly increases with the increase in matrix permeability. The optimal soaking time is linear with the increases of both oil viscosity and BHP and logarithmically declines with the increase in matrix permeability and specific surface area. Moreover, it shows a rising tendency as the interficial tension (IFT) increases. Overall, a general model was achieved to calculate the optimal soaking time.

scholarly journals Application of Bionic Technologies on the Fracturing Plug

Biomimetics ◽  
2019 ◽  
Vol 4 (4) ◽  
pp. 78
Author(s):  
Lin Chen ◽  
Ran Wei ◽  
Songbo Wei ◽  
Xinzhong Wang
Keyword(s):  
Hydraulic Fracturing ◽  
Dissolution Rate ◽  
Experimental Results ◽  
Hydrophobic Properties ◽  
Multi Stage ◽  
Bionic Surface ◽  
Zonal Isolation ◽  
Oil Gas

The dissolvable bridge plug is one of the most important tools for multi-stage hydraulic fracturing in the field of oil/gas development. The plug provides zonal isolation to realize staged stimulation and, after fracturing, the plug is fully dissolved in produced liquids. A bionic surface was introduced to improve the performance of the plug. Surface dimples in the micron dimension were prepared on the dissolvable materials of the plug. The experimental results showed that the surface dimples changed the hydrophilic and hydrophobic properties of the dissolvable materials. The dissolution rate has a great relation with the parameters of the dimples and can be controlled by choosing the dimples’ parameters to some degree.

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