Propped Fracture Conductivity in Shales

2013 ◽  
Author(s):  
Junjing Zhang ◽  
Anton Kamenov ◽  
Ding Zhu ◽  
A. Daniel Hill
Keyword(s):  
Hydraulic Fracture ◽  
Conductivity Measurement ◽  
Good Control ◽  
Natural Fracture ◽  
Well Performance ◽  
Fracture Conductivity ◽  
Low Viscosity ◽  
Bedding Planes ◽  
Series Of Experiments ◽  
Complicated Fracture

The successful development of the major shale gas plays in North America hinges upon the creation of complicated fracture networks by pumping low viscosity fracturing fluid with low proppant concentrations at high flow rate. Direct laboratory measurement of hydraulic fracture conductivity created in the networks is needed for reliable well performance analysis and fracture design optimization. A series of experiments were conducted under realistic hydraulic fracturing conditions to measure the conductivity using a modified API conductivity cell. Natural fractures were preserved and fracture infill was kept for initial conductivity measurement. Fractures were also induced along the natural bedding planes to obtain fracture surface asperities. Proppants of various sizes were placed between rough fracture surfaces at realistic concentrations. The two sides of the rough fractures were either aligned or displaced with a 0.1 inch offset. Results show that the hydraulic fracture conductivity of shale samples with rough surfaces can be accurately measured in a laboratory with appropriate experimental procedures and good control on experimental errors. The unpropped offset fracture can create conductivity as much as poorly cemented natural fracture, while the conductivity of unpropped matched fracture is minor. The presence of proppants can elevate the fracture conductivity by 2 to 3 orders of magnitude. Propped fracture conductivity increases with larger proppant size and higher proppant concentration. This study also indicates that within 20 hours propped fracture conductivity can be reduced by as much as 24% as shown in the longer term fracture conductivity measurements.

Comparison of Fractured-Horizontal-Well Performance in Tight Sand and Shale Reservoirs

2011 ◽  
Vol 14 (02) ◽  
pp. 248-259 ◽  
Author(s):  
E.. Ozkan ◽  
M Brown ◽  
R.. Raghavan ◽  
H.. Kazemi
Keyword(s):  
Hydraulic Fracture ◽  
Horizontal Well ◽  
Flow Model ◽  
Horizontal Wells ◽  
Natural Fracture ◽  
Well Performance ◽  
Fracture Conductivity ◽  
Fractured Horizontal Well ◽  
Shale Reservoirs ◽  
Fractured Horizontal Wells

Summary This paper presents a discussion of fractured-horizontal-well performance in millidarcy permeability (conventional) and micro- to nanodarcy permeability (unconventional) reservoirs. It provides interpretations of the reasons to fracture horizontal wells in both types of formations. The objective of the paper is to highlight the special productivity features of unconventional shale reservoirs. By using a trilinear-flow model, it is shown that the drainage volume of a multiple-fractured horizontal well in a shale reservoir is limited to the inner reservoir between the fractures. Unlike conventional reservoirs, high reservoir permeability and high hydraulic-fracture conductivity may not warrant favorable productivity in shale reservoirs. An efficient way to improve the productivity of ultratight shale formations is to increase the density of natural fractures. High natural-fracture conductivities may not necessarily contribute to productivity either. Decreasing hydraulic-fracture spacing increases the productivity of the well, but the incremental production gain for each additional hydraulic fracture decreases. The trilinear-flow model presented in this work and the information derived from it should help the design and performance prediction of multiple-fractured horizontal wells in shale reservoirs.

A New Method of Optimization Design of Hydraulic Fracture Parameters in Low Porosity and Fractured Gas Reservoir

2013 ◽  
Vol 380-384 ◽  
pp. 1656-1659
Author(s):  
Xiu Ling Han ◽  
Fu Jian Zhou ◽  
Chun Ming Xiong ◽  
Xiong Fei Liu ◽  
Xian You Yang
Keyword(s):  
Simulation Model ◽  
Hydraulic Fracture ◽  
Optimization Design ◽  
Outer Part ◽  
Gas Production ◽  
Natural Fracture ◽  
Fracture Permeability ◽  
Gas Reservoir ◽  
Fracture Conductivity ◽  
High Production Rate

A new composite reservoir simulation model of lower computation cost was used to optimize hydraulic fracture length and fracture conductivity during performing a hydraulic fracturing. The simulation model is divided into inner part and outer part. The inner part is dual-porosity and dual-permeability system, and the other is single porosity system. The research shows that the natural fracture permeability and density are the most influential parameters; a relative long fracture with high hydraulic fracture conductivity is required for a high production rate due to non-Darcy flow effects. A shorter primary fracture is better in a gas reservoir of high natural density. The composite model represents the flow characteristic more accurately and provides the optimal design of fracturing treatments to obtain an economic gas production.

Finite-Element Simulation of a Hydraulic Fracture Interacting With a Natural Fracture

SPE Journal ◽  
2016 ◽  
Vol 22 (01) ◽  
pp. 219-234 ◽  
Author(s):  
Zuorong Chen ◽  
Robert G. Jeffrey ◽  
Xi Zhang ◽  
James Kear
Keyword(s):  
Finite Element ◽  
Hydraulic Fracture ◽  
Injection Pressure ◽  
Quantitative Information ◽  
Injection Rate ◽  
Interfacial Stress ◽  
Natural Fracture ◽  
Fluid Viscosity ◽  
Fracturing Fluid ◽  
Bedding Planes

Summary In this paper, the problem of a hydraulic fracture (HF) interacting with a pre-existing natural fracture (NF) has been investigated with a cohesive zone finite-element model. The model fully couples fluid flow, fracture propagation, and elastic deformation, taking into account the friction between the contacting fracture surfaces and the interaction between the HF and the NF. The effect of the field conditions—such as in-situ stresses, rock and fracture mechanical and geometrical (initial conductivity of the NF) properties, intersection angle, and the treatment parameters (fracturing fluid viscosity and injection rate)—on the HF propagation behavior has been analyzed. The finite-element-modeling results provide detailed quantitative information on the development of various types of HF/NF interaction, interfacial stress distribution, fracture-geometry evolution, and injection-pressure history, and allow us to gain an in-depth understanding of the relative roles of various parameters. The value of a parameter calculated as the product of fracturing-fluid viscosity and injection rate can be used as an indicator to gauge if crossing or diverting behavior is more likely. In addition, using a finite-element approach allows the analysis to be extended to include the effects of fluid leakoff and poroelastic effect, and allows the study of HF height growth through a system of nonhomogeneous layers and their bedding planes.

scholarly journals Unconventional Well Test Analysis for Assessing Individual Fracture Stages through Post-Treatment Pressure Falloffs: Case Study

Energies ◽  
2021 ◽  
Vol 14 (20) ◽  
pp. 6747
Author(s):  
Abdulaziz Ellafi ◽  
Hadi Jabbari
Keyword(s):  
Oil Recovery ◽  
Hydraulic Fracture ◽  
Early Stage ◽  
Natural Fracture ◽  
Well Test ◽  
Well Performance ◽  
Secondary Fracture ◽  
Design For All ◽  
Fracture Closure ◽  
Pressure Analysis

Researchers and operators have recently become interested in the individual stage optimization of unconventional reservoir hydraulic fracture. These professionals aim to maximize well performance during an unconventional well’s early-stage and potential Enhanced Oil Recovery (EOR) lifespan. Although there have been advances in hydraulic fracturing technology that allow for the creation of large stimulated reservoir volumes (SRVs), it may not be optimal to use the same treatment design for all stages of a well or many wells in an area. We present a comprehensive review of the main approaches used to discuss applicability, pros and cons, and a detailed comparison between different methodologies. Our research outlines a combination of the Diagnostic Fracture Injection Test (DFIT) and falloff pressure analysis, which can help to design intelligent production and improve well performance. Our field study presents an unconventional well to explain the objective optimization workflow. The analysis indicates that most of the fracturing fluid was leaked off through natural fracture surface area and resulted in the estimation of larger values compared to the hydraulic fracture calculated area. These phenomena might represent a secondary fracture set with a high fracture closure stress activated in neighbor stages that was not well-developed in other sections. The falloff pressure analysis provides significant and vital information, assisting operators in fully understanding models for fracture network characterization.

Hydraulic Fracture Height Containment by Weak Horizontal Interfaces

2015 ◽  
Author(s):  
Dimitry Chuprakov ◽  
Romain Prioul
Keyword(s):  
Hydraulic Fracture ◽  
Low Viscosity ◽  
Bedding Planes ◽  
Containment Model ◽  
Fracturing Fluids ◽  
Contrast Mechanism ◽  
Fracture Height ◽  
Fracture Height Containment ◽  
Stress Contrast ◽  
The Given

Abstract Weak formation bedding planes create a unique mechanism for hydraulic fracture height containment. They arrest the vertical growth of hydraulic fracture. The propagation across them may or may not occur. To quantify this fracture behavior, first we developed an analytical model of the elastic T-shaped fracture contact with frictional and cohesional interfaces. The model evaluates the fracture blunting and the shear activation of the interfaces. It predicts the buildup of the net pressure necessary for the fracture to cross the given interface. Next we conduct numerical simulations of the 3D fracture propagation in a formation with closely spaced horizontal interfaces. These simulations manifest intermittent and decelerated fracture growth in height, especially with low-viscosity fracturing fluids. This mechanism of fracture height containment is independent of the multilayer stress-contrast mechanism used conventionally. Combined with the stress mechanism, the fracture height containment model could alleviate the problem of height growth overestimation in some fracturing simulation cases.

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.

scholarly journals Deformation Behavior between Hydraulic and Natural Fractures Using Fully Coupled Hydromechanical Model with XFEM

2017 ◽  
Vol 2017 ◽  
pp. 1-12 ◽  
Author(s):  
Fei Liu ◽  
Zhifeng Luo ◽  
Yu Sang ◽  
Liqiang Zhao ◽  
Changlin Zhou
Keyword(s):  
Hydraulic Fracture ◽  
Fluid Pressure ◽  
Interaction Mechanism ◽  
Natural Fracture ◽  
Natural Fractures ◽  
Deformation Response ◽  
Stress Shadow ◽  
Complicated Fracture ◽  
Fully Coupled ◽  
Hydromechanical Model

There has been a growing consensus that preexisting natural fractures play an important role during stimulation. A novel fully coupled hydromechanical model using extended finite element method is proposed. This directly coupled scheme avoids the cumbersome process during calculating the fluid pressure in complicated fracture networks and translating into an equivalent nodal force. Numerical examples are presented to simulate the hydraulic fracture propagation paths for simultaneous multifracture treatments with properly using the stress shadow effects for horizontal wells and to reveal the deformation response and interaction mechanism between hydraulic induced fracture and nonintersected natural fractures at orthotropic and nonorthotropic angles. With the stress shadow effects, the induced hydraulic flexural fracture deflecting to wellbore rather than transverse fracture would be formed during the progress of simultaneous fracturing for a horizontal well. The coupled hydromechanical simulation reveals that the adjacent section to the intersection is opened and the others are closed for orthogonal natural fracture, while the nonorthogonal natural fracture is activated near the intersection firstly and along the whole section with increasing perturbed stresses. The results imply that the induced hydraulic fracture tends to cross orthotropic natural fracture, while it is prior to being arrested by the nonorthotropic natural fracture.

A Semianalytical Model for Production Simulation From Nonplanar Hydraulic-Fracture Geometry in Tight Oil Reservoirs

SPE Journal ◽  
2016 ◽  
Vol 21 (03) ◽  
pp. 1028-1040 ◽  
Author(s):  
Wei Yu ◽  
Kan Wu ◽  
Kamy Sepehrnoori
Keyword(s):  
Hydraulic Fracture ◽  
Transient Flow ◽  
Flow Behavior ◽  
Tight Oil ◽  
Well Performance ◽  
Fracture Permeability ◽  
Fracture Geometry ◽  
Fracture Conductivity ◽  
Fracture Width ◽  
Stress Dependent

Summary Two key technologies such as horizontal drilling and hydraulic fracturing have led to the economic production of unconventional resources such as shale gas and tight oil. In reality, a nonplanar hydraulic-fracture geometry with varying fracture width and fracture permeability is created during the hydraulic-fracturing process. However, it is challenging to simulate well performance from the nonplanar fracture geometry. For the sake of simplicity, the nonplanar fracture geometry is often represented by ideal planar fracture geometry with constant fracture width, which one can easily handle analytically, semianalytically, and numerically. However, such ideal fracture geometry is inadequate to capture the physics of the transient flow behavior of the nonplanar fracture geometry. Although significant efforts were made in recent years to numerically model well performance from the complex fracture geometry, these approaches are still challenging to model the nonplanar fracture geometry with varying width because of a large considerable fracture-gridding issues and an expensive computation cost. In addition, the effect of nonplanar fracture geometry on well productivity and transient flow behavior was not reported in the literature. Hence, a model to handle the nonplanar fracture geometry by considering varying fracture width and fracture permeability is still lacking in the petroleum industry. Zhou et al. (2014) proposed a semianalytical model to handle the complex fracture geometry with constant fracture width. However, the semianalytical model did not consider the effects of stress-dependent fracture conductivity and the nonplanar fracture geometry as well as planar fracture geometry with varying fracture width along the fracture. In this work, we extended the semianalytical model to simulate production from the nonplanar fracture geometry as well as planar fracture geometry with varying width. In addition, the effect of stress-dependent fracture conductivity was implemented in the model. We verified the semianalytical model against a numerical reservoir simulator for single planar fracture with constant width. We performed two case studies. The first case contains a comparison of two planar fractures, one with constant fracture width and another with varying fracture width. In the second study, we compared two fractures with different fracture geometries such as planar fracture geometry and nonplanar fracture geometry, which were generated from the fracture-propagation model. In addition, transient flow regimes were investigated on the basis of a log-log graph of the dimensionless pressure drop and pressure-drop derivative vs. the dimensionless time. This work can provide critical insights into understanding the well performance from tight oil reservoirs with the nonplanar hydraulic-fracture geometry.

scholarly journals The Investigation on Initiation and Propagation of Hydraulic Fractures in Shale Reservoir

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-19
Author(s):  
Xiangjun Liu ◽  
Wei Lei ◽  
Jing Huang ◽  
Yi Ding ◽  
Lixi Liang ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
Bedding Plane ◽  
Fracture Network ◽  
Natural Fracture ◽  
Strong Anisotropy ◽  
Bedding Planes ◽  
Initiation And Propagation ◽  
Shale Reservoir

Hydraulic fracturing is a necessary technique for shale gas exploitation. In order to have efficient stimulation treatment, a complex fracture network has to be developed, whereas with rich bedding planes and natural fractures, the mechanism of forming a fracture network is not fully understood and it is so tricky to predict propagation and initiation of hydraulic fracture. Therefore, in this paper, considering the strong anisotropy of shale reservoir, numerical simulation has been conducted to analyze fracture propagation and initiation on the basis of finite element and damage mechanics. Simulation results indicate that hydraulic fracture is not merely controlled by in situ stress due to strong anisotropy in shale. With plenty of bedding planes, hydraulic fracture tends to have initiation and propagation along the bedding plane. In particular, this influence becomes stronger with low strength and high development density of bedding planes. Additionally, in combination with natural fracture and bedding plane, the initiation point is usually on a natural fracture plane, causing relatively small breakdown pressure. In the process of fracture propagation, hydraulic fracture connects with natural fractures and bedding planes, forming dendritic bifurcation and more complicated paths. Numerical simulation proves that bedding plane and natural fracture are vital factors of hydraulic fracture. Compared to natural fracture, the bedding plane has a stronger impact on hydraulic fracture propagation. For the initiation of hydraulic fracture, natural fracture is the major effecting factor. The outcome of this study is able to offer theoretical guidance for hydraulic fracturing in shale.

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