The Effects of Perforation Erosion on Practical Hydraulic-Fracturing Applications

SPE Journal ◽  
2017 ◽  
Vol 22 (02) ◽  
pp. 645-659 ◽  
Author(s):  
Gongbo Long ◽  
Guanshui Xu
Keyword(s):  
Hydraulic Fracturing ◽  
Horizontal Wells ◽  
In Situ Stress ◽  
Fluid Distribution ◽  
Fluid Viscosity ◽  
Appropriate Treatment ◽  
Limited Entry ◽  
Successful Design ◽  
Treatment Designs

Summary Predicting perforation erosion and its effects on fracture dimensions, fluid distribution, and pressure drop can be an essential part of successful design of hydraulic-fracturing treatments, especially for massive treatments along the horizontal wells when limited-entry techniques are implemented. Both the perforation diameter D and discharge coefficient Cd increase dynamically as proppant-laden slurries are pumped through perforations, making it necessary to consider the changes of these two variables in terms of time to predict the perforation-erosion effects. In this paper, we conduct a study of the perforation-erosion effects by implementing our new perforation-erosion model derived from experimentally verified abrasion mechanisms to calculate the rate changes of these two variables and the consequent influence on the fracture dimensions, fluid distribution, and downhole pressure during a treatment. The selected parameters affecting the erosion effects in the study include perforation number, perforation-cluster spacing, in-situ stress difference, and fracturing-fluid viscosity. The results demonstrate that our model can predict the perforation-erosion effects on practical hydraulic-fracturing applications in a physically clear and mathematically concise manner under different circumstances by inspecting the simultaneous increases of D and Cd separately, leading to more-appropriate treatment designs, especially with the limited-entry techniques.

scholarly journals Study on Propagation Behaviors of Hydraulic Fracture Network in Tight Sandstone Formation with Closed Cemented Natural Fractures

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-22
Author(s):  
Jun Zhang ◽  
Yu-Wei Li ◽  
Wei Li ◽  
Zi-Jie Chen ◽  
Yuan Zhao ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Fracture Network ◽  
In Situ Stress ◽  
Injection Rate ◽  
Fluid Viscosity ◽  
Tight Sandstone ◽  
Propagation Behavior ◽  
Sandstone Formation

Natural fractures in tight sandstone formation play a significant role in fracture network generation during hydraulic fracturing. This work presents an experimental model of tight sandstone with closed cemented preexisting fractures. The influence of closed cemented fractures’ (CCF) directions on the propagation behavior of hydraulic fracture (HF) is studied based on the hydraulic fracturing experiment. A field-scaled numerical model used to simulate the propagation of HF is established based on the flow-stress-damage (FSD) coupled method. This model contains the discrete fracture network (DFN) generated by the Monte-Carlo method and is used to investigate the effects of CCFs’ distribution, CCFs’ strength, and in-situ stress anisotropy, injection rate, and fluid viscosity on the propagation behavior of fracture network. The results show that the distribution direction of CCFs is critical for the formation of complex HFs. When the angle between the horizontal maximum principal stress direction and the CCFs is in the range of 30° to 60°, the HF network is the most complex. There are many kinds of compound fracture propagation patterns, such as crossing, branching, and deflection. The increase of CCFs’ strength is not conducive to the generation of branched and deflected fractures. When the in-situ stress difference ranges from 3 MPa to 6 MPa, the HF network’s complexity and propagation range can be guaranteed simultaneously. The increase in the injection rate will promote the formation of the complex HF network. The proper increase of fracturing fluid viscosity can promote HF’s propagation. However, when the viscosity is too high, the complex HFs only appear around the wellbore. The research results can provide new insights for the hydraulic fracturing optimization design of naturally fractured tight sandstone formation.

scholarly journals Fracture Propagation and Morphology Due to Non-Aqueous Fracturing: Competing Roles between Fluid Characteristics and In Situ Stress State

Minerals ◽  
2020 ◽  
Vol 10 (5) ◽  
pp. 428
Author(s):  
Yunzhong Jia ◽  
Zhaohui Lu ◽  
Hong Liu ◽  
Jiehao Wang ◽  
Yugang Cheng ◽  
...  
Keyword(s):  
Carbon Dioxide ◽  
Hydraulic Fracturing ◽  
Fracture Propagation ◽  
Horizontal Stress ◽  
In Situ Stress ◽  
Fluid Viscosity ◽  
Low Viscosity ◽  
Fracturing Process ◽  
Fluid Characteristics

Non-aqueous or gaseous stimulants are alternative working fluids to water for hydraulic fracturing in shale reservoirs, which offer advantages including conserving water, avoiding clay swelling and decreasing formation damage. Hence, it is crucial to understand fluid-driven fracture propagation and morphology in shale formations. In this research, we conduct fracturing experiments on shale samples with water, liquid carbon dioxide, and supercritical carbon dioxide to explore the effect of fluid characteristics and in situ stress on fracture propagation and morphology. Moreover, a numerical model that couples rock property heterogeneity, micro-scale damage and fluid flow was built to compare with experimental observations. Our results indicate that the competing roles between fluid viscosity and in situ stress determine fluid-driven fracture propagation and morphology during the fracturing process. From the macroscopic aspect, fluid-driven fractures propagate to the direction of maximum horizontal stress direction. From the microscopic aspect, low viscosity fluid easily penetrates into pore throats and creates branches and secondary fractures, which may deflect the main fracture and eventually form the fracture networks. Our results provide a new understanding of fluid-driven fracture propagation, which is beneficial to fracturing fluid selection and fracturing strategy optimization for shale gas hydraulic fracturing operations.

The Application of Hydraulic Fracturing in Storage Projects of Liquefied Petroleum Gas

2006 ◽  
Vol 306-308 ◽  
pp. 1509-1514 ◽  
Author(s):  
Jing Feng ◽  
Qian Sheng ◽  
Chao Wen Luo ◽  
Jing Zeng
Keyword(s):  
Rock Mass ◽  
Hydraulic Fracturing ◽  
Stress Measurement ◽  
Test Procedure ◽  
In Situ Stress ◽  
Test System ◽  
Petroleum Engineering ◽  
Liquefied Petroleum Gas

It is very important to study the pristine stress field in Civil, Mining, Petroleum engineering as well as in Geology, Geophysics, and Seismology. There are various methods of determination of in-situ stress in rock mass. However, hydraulic fracturing techniques is the most convenient method to determine and interpret the test results. Based on an hydraulic fracturing stress measurement campaign at an underground liquefied petroleum gas storage project which locates in ZhuHai, China, this paper briefly describes the various uses of stress measurement, details of hydraulic fracturing test system, test procedure adopted and the concept of hydraulic fracturing in arriving at the in-situ stresses of the rock mass.

scholarly journals Fracturing curve and its corresponding gas productivity of coalbed methane wells in the Zhengzhuang block, southern Qinshui Basin, North China

2020 ◽  
Vol 38 (5) ◽  
pp. 1387-1408
Author(s):  
Yang Chen ◽  
Dameng Liu ◽  
Yidong Cai ◽  
Jingjie Yao
Keyword(s):  
Hydraulic Fracturing ◽  
Coalbed Methane ◽  
Continuous Production ◽  
Fracture Morphology ◽  
Geological Structure ◽  
In Situ Stress ◽  
Gas Production ◽  
Type Curves ◽  
Stable Type

Hydraulic fracturing has been widely used in low permeability coalbed methane reservoirs to enhance gas production. To better evaluate the hydraulic fracturing curve and its effect on gas productivity, geological and engineering data of 265 development coalbed methane wells and 14 appraisal coalbed methane wells in the Zhengzhuang block were investigated. Based on the regional geologic research and statistical analysis, the microseismic monitoring results, in-situ stress parameters, and gas productivity were synthetically evaluated. The results show that hydraulic fracturing curves can be divided into four types (descending type, stable type, wavy type, and ascending type) according to the fracturing pressure and fracture morphology, and the distributions of different type curves have direct relationship with geological structure. The vertical in-situ stress is greater than the closure stress in the Zhengzhuang block, but there is anomaly in the aggregation areas of the wavy and ascending fracturing curves, which is the main reason for the development of multi-directional propagated fractures. The fracture azimuth is consistent with the regional maximum principle in-situ stress direction (NE–NEE direction). Furthermore, the 265 fracturing curves indicate that the coalbed methane wells owned descending, and stable-type fracturing curves possibly have better fracturing effect considering the propagation pressure gradient (FP) and instantaneous shut-in pressure (PISI). Two fracturing-productivity patterns are summarized according to 61 continuous production wells with different fracturing type and their plane distribution, which indicates that the fracturing effect of different fracturing curve follows the pattern: descending type > stable type > wavy type > ascending type.

Optimization of In-Stage Diversion To Promote Uniform Planar Multifracture Propagation: A Numerical Study

SPE Journal ◽  
2020 ◽  
Vol 25 (06) ◽  
pp. 3091-3110
Author(s):  
Ming Chen ◽  
Shicheng Zhang ◽  
Tong Zhou ◽  
Xinfang Ma ◽  
Yushi Zou
Keyword(s):  
Numerical Study ◽  
High Stress ◽  
In Situ Stress ◽  
Stress Difference ◽  
Multiple Fractures ◽  
Stress Shadow ◽  
Limited Entry ◽  
Fully Coupled ◽  
Flux Redistribution

Summary Creating uniform multiple fractures is a challenging task due to reservoir heterogeneity and stress shadow. Limited-entry perforation and in-stage diversion are commonly used to improve multifracture treatments. Many studies have investigated the mechanism of limited-entry perforation for multifracture treatments, but relatively few have focused on the in-stage diversion process. The design of in-stage diversion is usually through trial and error because of the lack of a simulator. In this study, we present a fully coupled planar 2D multifracture model for simulating the in-stage diversion process. The objective is to evaluate flux redistribution after diversion and optimize the dosage of diverters and diversion timing under different in-stage in-situ stress difference. Our model considers ball sealer allocation and solves flux redistribution after diversion through a fully coupled multifracture model. A supertimestepping explicit algorithm is adopted to solve the solid/fluid coupling equations efficiently. Multifracture fronts are captured by using tip asymptotes and an adaptive time-marching approach. The modeling results are validated against analytical solutions for a plane-strain Khristianovic-Geertsma de Klerk (KGD) model. A series of numerical simulations are conducted to investigate the multifracture growth under different in-stage diversion operations. Parametric studies reveal that the in-stage in-situ stress difference is a critical parameter for diversion designs. When the in-situ stress difference is larger than 2 MPa, the fracture in the high-stress zone can hardly be initiated before diversion for a general fracturing design. More ball sealers are required for the formations with higher in-stage in-situ stress difference. The diverting time should be earlier for formations with high in-stage stress differences as well. Adding more perforation holes in the zone with higher in-situ stress is recommended to achieve even flux distribution. The results of this study can help understand the multifracture growth mechanism during in-stage diversion and optimize the diversion design timely.

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