scholarly journals Transient Pressure Behavior of Complex Fracture Networks in Unconventional Reservoirs

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-11
Author(s):  
Gou Feifei ◽  
Liu Chuanxi ◽  
Ren Zongxiao ◽  
Qu Zhan ◽  
Wang Sukai ◽  
...  
Keyword(s):  
Fracture Network ◽  
Unconventional Reservoirs ◽  
Transitional Flow ◽  
Natural Fractures ◽  
Fracture Networks ◽  
Transient Pressure ◽  
Horizontal Drilling ◽  
Pressure Behavior ◽  
Complex Fracture ◽  
Complex Fracture Network

Unconventional resources have been successfully exploited with technological advancements in horizontal-drilling and multistage hydraulic-fracturing, especially in North America. Due to preexisting natural fractures and the presence of stress isotropy, several complex fracture networks can be generated during fracturing operations in unconventional reservoirs. Using the DVS method, a semianalytical model was created to analyze the transient pressure behavior of a complex fracture network in which hydraulic and natural fractures interconnect with inclined angles. In this model, the complex fracture network can be divided into a proper number of segments. With this approach, we are able to focus on a detailed description of the network properties, such as the complex geometry and varying conductivity of the fracture. The accuracy of the new model was demonstrated by ECLIPSE. Using this method, we defined six flow patterns: linear flow, fracture interference flow, transitional flow, biradial flow, pseudoradial flow, and boundary response flow. A sensitivity analysis was conducted to analyze each of these flow regimes. This work provides a useful tool for reservoir engineers for fracture designing as well as estimating the performance of a complex fracture network.

scholarly journals Semianalytical Coupled Model of Transient Pressure Behavior for Horizontal Well with Complex Fracture Networks in Tight Oil Reservoirs

2019 ◽  
Vol 2019 ◽  
pp. 1-12
Author(s):  
Ren Zongxiao ◽  
Du Kun ◽  
Shi Junfeng ◽  
Liu Wenqiang ◽  
Qu Zhan ◽  
...  
Keyword(s):  
Horizontal Well ◽  
Variable Mass ◽  
Fracture Network ◽  
Fracture Networks ◽  
Transient Pressure ◽  
Pressure Behavior ◽  
Complex Fracture ◽  
Complex Fracture Network ◽  
Horizontal Wellbore ◽  
Seepage Model

Due to a large number of natural fractures in tight oil reservoir, many complex fracture networks are generated during fracturing operation. There are five kinds of flow media in the reservoir: “matrix, natural fracture, hydraulic fracture network, perforation hole, and horizontal wellbore”. How to establish the seepage model of liquid in multiscale medium is a challenging problem. Firstly, this paper establishes the dual medium seepage model based on source function theory, principle of superposition, and Laplace transformation and then uses the “star-triangle” transform method to establish the transient pressure behavior model in the complex fracture network. After that, perforating seepage model and variable mass flow in horizontal wellbore were established. Finally, continuous condition was used to couple the seepage model of dual medium seepage model, transient pressure behavior model in the complex fracture network, perforation seepage model, and the variable mass seepage model in horizontal wellbore, to establish a semianalytical coupled seepage model for horizontal well in tight reservoir. This paper provides theoretical basis for field application of horizontal well with complex fracture networks.

Predicting Well Performance in Naturally Fractured Reservoir

2013 ◽  
Author(s):  
Yunsuk Hwang ◽  
Jiajing Lin ◽  
David Schechter ◽  
Ding Zhu
Keyword(s):  
Hydraulic Fracture ◽  
Fracture Network ◽  
Darcy Flow ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Well Performance ◽  
Fracture Networks ◽  
Complex Fracture ◽  
Complex Fracture Network

Multiple hydraulic fracture treatments in reservoirs with natural fractures create complex fracture networks. Predicting well performance in such a complex fracture network system is an extreme challenge. The statistical nature of natural fracture networks changes the flow characteristics from that of a single linear fracture. Simply using single linear fracture models for individual fractures, and then summing the flow from each fracture as the total flow rate for the network could introduce significant error. In this paper we present a semi-analytical model by a source method to estimate well performance in a complex fracture network system. The method simulates complex fracture systems in a more reasonable approach. The natural fracture system we used is fractal discrete fracture network model. We then added multiple dominating hydraulic fractures to the natural fracture system. Each of the hydraulic fractures is connected to the horizontal wellbore, and some of the natural fractures are connected to the hydraulic fractures through the network description. Each fracture, natural or hydraulically induced, is treated as a series of slab sources. The analytical solution of superposed slab sources provides the base of the approach, and the overall flow from each fracture and the effect between the fractures are modeled by applying the superposition principle to all of the fractures. The fluid inside the natural fractures flows into the hydraulic fractures, and the fluid of the hydraulic fracture from both the reservoir and the natural fractures flows to the wellbore. This paper also shows that non-Darcy flow effects have an impact on the performance of fractured horizontal wells. In hydraulic fracture calculation, non-Darcy flow can be treated as the reduction of permeability in the fracture to a considerably smaller effective permeability. The reduction is about 2% to 20%, due to non-Darcy flow that can result in a low rate. The semi-analytical solution presented can be used to efficiently calculate the flow rate of multistage-fractured wells. Examples are used to illustrate the application of the model to evaluate well performance in reservoirs that contain complex fracture networks.

Numerical Simulation of Complex Fracture Network Development by Hydraulic Fracturing in Naturally Fractured Ultratight Formations

2013 ◽  
Author(s):  
Hannes Hofmann ◽  
Tayfun Babadagli ◽  
Günter Zimmermann
Keyword(s):  
Fracture Network ◽  
Natural Fracture ◽  
Fracture Networks ◽  
Network Development ◽  
Complex Fracture ◽  
Fracture Patterns ◽  
Fracture Systems ◽  
Fracture Development ◽  
Complex Fracture Network ◽  
Treatment Designs

The creation of large complex fracture networks by hydraulic fracturing is imperative for enhanced oil recovery from tight sand or shale reservoirs, tight gas extraction, and Hot-Dry-Rock (HDR) geothermal systems to improve the contact area to the rock matrix. Although conventional fracturing treatments may result in bi-wing fractures, there is evidence by microseismic mapping that fracture networks can develop in many unconventional reservoirs, especially when natural fracture systems are present and the differences between the principle stresses are low. However, not much insight is gained about fracture development as well as fluid and proppant transport in naturally fractured tight formations. In order to clarify the relationship between rock and treatment parameters, and resulting fracture properties, numerical simulations were performed using a commercial Discrete Fracture Network (DFN) simulator. A comprehensive sensitivity analysis is presented to identify typical fracture network patterns resulting from massive water fracturing treatments in different geological conditions. It is shown how the treatment parameters influence the fracture development and what type of fracture patterns may result from different treatment designs. The focus of this study is on complex fracture network development in different natural fracture systems. Additionally, the applicability of the DFN simulator for modeling shale gas stimulation and HDR stimulation is critically discussed. The approach stated above gives an insight into the relationships between rock properties (specifically matrix properties and characteristics of natural fracture systems) and the properties of developed fracture networks. Various simulated scenarios show typical conditions under which different complex fracture patterns can develop and prescribe efficient treatment designs to generate these fracture systems. Hydraulic stimulation is essential for the production of oil, gas, or heat from ultratight formations like shales and basement rocks (mainly granite). If natural fracture systems are present, the fracturing process becomes more complex to simulate. Our simulation results reveal valuable information about main parameters influencing fracture network properties, major factors leading to complex fracture network development, and differences between HDR and shale gas/oil shale stimulations.

Numerical Simulation of Complex Fracture Network Development by Hydraulic Fracturing in Naturally Fractured Ultratight Formations

2014 ◽  
Vol 136 (4) ◽  
Author(s):  
Hannes Hofmann ◽  
Tayfun Babadagli ◽  
Günter Zimmermann
Keyword(s):  
Fracture Network ◽  
Natural Fracture ◽  
Fracture Networks ◽  
Network Development ◽  
Complex Fracture ◽  
Fracture Patterns ◽  
Fracture Systems ◽  
Fracture Development ◽  
Complex Fracture Network ◽  
Treatment Designs

The creation of large complex fracture networks by hydraulic fracturing is imperative for enhanced oil recovery from tight sand or shale reservoirs, tight gas extraction, and hot-dry-rock (HDR) geothermal systems to improve the contact area to the rock matrix. Although conventional fracturing treatments may result in biwing fractures, there is evidence by microseismic mapping that fracture networks can develop in many unconventional reservoirs, especially when natural fracture systems are present and the differences between the principle stresses are low. However, not much insight is gained about fracture development as well as fluid and proppant transport in naturally fractured tight formations. In order to clarify the relationship between rock and treatment parameters, and resulting fracture properties, numerical simulations were performed using a commercial discrete fracture network (DFN) simulator. A comprehensive sensitivity analysis is presented to identify typical fracture network patterns resulting from massive water fracturing treatments in different geological conditions. It is shown how the treatment parameters influence the fracture development and what type of fracture patterns may result from different treatment designs. The focus of this study is on complex fracture network development in different natural fracture systems. Additionally, the applicability of the DFN simulator for modeling shale gas stimulation and HDR stimulation is critically discussed. The approach stated above gives an insight into the relationships between rock properties (specifically matrix properties and characteristics of natural fracture systems) and the properties of developed fracture networks. Various simulated scenarios show typical conditions under which different complex fracture patterns can develop and prescribe efficient treatment designs to generate these fracture systems. Hydraulic stimulation is essential for the production of oil, gas, or heat from ultratight formations like shales and basement rocks (mainly granite). If natural fracture systems are present, the fracturing process becomes more complex to simulate. Our simulations suggest that stress state, in situ fracture networks, and fluid type are the main parameters influencing hydraulic fracture network development. Major factors leading to more complex fracture networks are an extensive pre-existing natural fracture network, small fracture spacings, low differences between the principle stresses, well contained formations, high tensile strength, high Young’s modulus, low viscosity fracturing fluid, and large fluid volumes. The differences between 5 km deep granitic HDR and 2.5 km deep shale gas stimulations are the following: (1) the reservoir temperature in granites is higher, (2) the pressures and stresses in granites are higher, (3) surface treatment pressures in granites are higher, (4) the fluid leak-off in granites is less, and (5) the mechanical parameters tensile strength and Young’s modulus of granites are usually higher than those of shales.

scholarly journals Study on the Interaction Mechanism of Hydraulic Fracture and Natural Fracture in Shale Formation

Energies ◽  
2019 ◽  
Vol 12 (23) ◽  
pp. 4477 ◽  
Author(s):  
Heng Zheng ◽  
Chunsheng Pu ◽  
CHOE TONG IL
Keyword(s):  
Hydraulic Fracture ◽  
Shear Failure ◽  
Fracture Network ◽  
Tensile Failure ◽  
Natural Fracture ◽  
Natural Fractures ◽  
Propagation Length ◽  
Complex Fracture ◽  
Geological Conditions ◽  
Complex Fracture Network

Hydraulic fracturing is an essential technique for the development of shale gas, due to the low permeability in formation. Abundant natural fractures contained in a formation are indispensable for the development of a fracture network. In this paper, a damage-stress-seepage coupled hydraulic fracture expansion model, based on the extended finite element method, is established. The simulation results show that shear failure occurs when the hydraulic fracture interacts with a frictional natural fracture, while tensile failure occurs when it interacts with a cement natural fracture. Low interaction angles and high tensile strength of the rock are beneficial for the generation of a complex fracture network. Furthermore, under the same geological conditions and injection parameters, frictional natural fractures are more beneficial for the generation of a complex fracture network, when compared with cement natural fractures. This can not only effectively increase the propagation length of the natural fracture, but also effectively reduce its reactive resistance. This research is of great significance for the efficient exploitation of unconventional oil and gas resources.

Production-Decline Models Using Anomalous Diffusion Stemming From a Complex Fracture Network

SPE Journal ◽  
2019 ◽  
Vol 24 (06) ◽  
pp. 2609-2634 ◽  
Author(s):  
Shuai Liu ◽  
Peter P. Valkó
Keyword(s):  
Anomalous Diffusion ◽  
Time Derivative ◽  
Horizontal Wells ◽  
Fracture Network ◽  
Production Data ◽  
Fracture Networks ◽  
Type Curves ◽  
Complex Fracture ◽  
Complex Fracture Network ◽  
Fractional Time Derivative

Summary In this work, we develop a well–based fractional–production–decline model, which resorts to anomalous diffusion to characterize the heterogeneity of complex fracture networks and can be conveniently used to interpret the rate and cumulative data in the early and middle times of production from multifractured horizontal wells in unconventional reservoirs. We first develop a model (the fracture–based model) to be used in inverse problems by simplifying the fractional–time–derivative model using the traditional multiple–planar–fracture framework to essentially contain three parameters (α,Ar, and Ix). After performing tests with elaborate synthetic cases, the trace of anomalous diffusion is captured but the drawbacks of this model are also detected and analyzed. Then, by focusing on improving the fracture–based model, we consider an infinite–conductivity horizontal well draining a complex fracture network through a fractional–flux–related skin. The improved model (the well–based model) is bolstered with the corresponding type curves regarding production rate and cumulative production, which can be applied to interpret the single–phase production in the early and middle times and to mainly characterize the fracture–network–related heterogeneity reflected in the production data during this early–to–middle period. The well–based model is applied to two synthetic cases with explicitly modeled complex fracture networks and to the cases of multifracture horizontal wells in the Permian Basin. The results of all case studies display good matches between our model and the production data, which indicates the model's capability to accurately describe the transient regime of the flow in the extremely heterogeneous fracture networks on the basis of average values of the formation properties.

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