scholarly journals Analysis of hydraulic fracture behavior and well pattern optimization in anisotropic coal reservoirs

2020 ◽  
pp. 014459872096083
Author(s):  
Yulong Liu ◽  
Dazhen Tang ◽  
Hao Xu ◽  
Wei Hou ◽  
Xia Yan
Keyword(s):  
Hydraulic Fracture ◽  
Coalbed Methane ◽  
Fracture Network ◽  
Simulation Software ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Well Pattern ◽  
Well Pattern Optimization ◽  
The Impact

Macrolithotypes control the pore-fracture distribution heterogeneity in coal, which impacts stimulation via hydrofracturing and coalbed methane (CBM) production in the reservoir. Here, the hydraulic fracture was evaluated using the microseismic signal behavior for each macrolithotype with microfracture imaging technology, and the impact of the macrolithotype on hydraulic fracture initiation and propagation was investigated systematically. The result showed that the propagation types of hydraulic fractures are controlled by the macrolithotype. Due to the well-developed natural fracture network, the fracture in the bright coal is more likely to form the “complex fracture network”, and the “simple” case often happens in the dull coal. The hydraulic fracture differences are likely to impact the permeability pathways and the well productivity appears to vary when developing different coal macrolithtypes. Thus, considering the difference of hydraulic fracture and permeability, the CBM productivity characteristics controlled by coal petrology were simulated by numerical simulation software, and the rationality of well pattern optimization factors for each coal macrolithotype was demonstrated. The results showed the square well pattern is more suitable for dull coal and semi-dull coal with undeveloped natural fractures, while diamond and rectangular well pattern is more suitable for semi-bright coal and bright coal with more developed natural fractures and more complex fracturing fracture network; the optimum wells spacing of bright coal and semi-bright coal is 300 m and 250 m, while that of semi-dull coal and dull coal is just 200 m.

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.

Natural-hydraulic fracture interaction: Microseismic observations and geomechanical predictions

2015 ◽  
Vol 3 (3) ◽  
pp. SU17-SU31 ◽  
Author(s):  
Jian Huang ◽  
Reza Safari ◽  
Uno Mutlu ◽  
Kevin Burns ◽  
Ingo Geldmacher ◽  
...  
Keyword(s):  
Sensitivity Analysis ◽  
Hydraulic Fracture ◽  
Fracture Network ◽  
Natural Fracture ◽  
Design Parameters ◽  
Reservoir Area ◽  
Complex Fracture ◽  
Model Complex ◽  
Fracture Interaction ◽  
The Impact

Natural fractures can reactivate during hydraulic stimulation and interact with hydraulic fractures producing a complex and highly productive natural-hydraulic fracture network. This phenomenon and the quality of the resulting conductive reservoir area are primarily functions of the natural fracture network characteristics (e.g., spacing, height, length, number of fracture sets, orientation, and frictional properties); in situ stress state (e.g., stress anisotropy and magnitude); stimulation design parameters (e.g., pumping schedule, the type/volume of fluid[s], and proppant); well architecture (number and spacing of stages, perforation length, well orientation); and the physics of the natural-hydraulic fracture interaction (e.g., crossover, arrest, reactivation). Geomechanical models can quantify the impact of key parameters that control the extent and complexity of the conductive reservoir area, with implications to stimulation design and well optimization in the field. We have developed a series of geomechanical simulations to predict natural-hydraulic fracture interaction and the resulting fracture network in complex settings. A geomechanics-based sensitivity analysis was performed that integrated key reservoir-geomechanical parameters to forward model complex fracture network generation, synthetic microseismic (MS) response, and associated conductivity paths as they evolve during stimulation operations. The simulations tested two different natural-hydraulic fracture interaction scenarios and could generate synthetic MS events. The sensitivity analysis revealed that geomechanical models that involve complex fracture networks can be calibrated against MS data and can help to predict the reservoir response to stimulation and optimize the conductive reservoir area. We analyzed a field data set (obtained from two hydraulically fractured wells in the Barnett Formation, Tarrant County, Texas) and established a coupling between the geomechanics and MS within the framework of a 3D geologic model. This coupling provides a mechanics-based approach to (1) verify MS trends and anomalies in the field, (2) optimize conductive reservoir area for reservoir simulations, and (3) improve stimulation design on the current well in near-real-time and well design/stimulation for future wells.

scholarly journals Hydraulic-Fracture-Height Growth Under the Combined Influence of Stress Barriers and Natural Fractures

SPE Journal ◽  
2018 ◽  
Vol 24 (01) ◽  
pp. 302-318 ◽  
Author(s):  
Jixiang Huang ◽  
Joseph P. Morris ◽  
Pengcheng Fu ◽  
Randolph R. Settgast ◽  
Christopher S. Sherman ◽  
...  
Keyword(s):  
Hydraulic Fracture ◽  
Fluid Pressure ◽  
Height Growth ◽  
Two Dimensions ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
3D Interaction ◽  
Fracture Height ◽  
Fully Coupled

Summary A fully coupled finite-element/finite-volume code is used to model 3D hydraulically driven fractures under the influence of strong vertical variations in closure stress interacting with natural fractures. Previously unknown 3D interaction mechanisms on fracture-height growth are revealed. Slipping of a natural fracture, triggered by elevated fluid pressure from an intersecting hydraulic fracture, can induce both increases and decreases of normal stress in the minimum-horizontal-stress direction, toward the center and tip of the natural fracture, respectively. Consequently, natural fractures are expected to be able to both encourage and inhibit the progress of hydraulic fractures propagating through stress barriers, depending on the relative locations between the intersecting fractures. Once the hydraulic fracture propagates above the stress barrier through the weakened segment near a favorably located natural fracture, a configuration consisting of two opposing fractures cuts the stress barrier from above and below. The fluid pressure required to break the stress barrier under such opposing-fracture configurations is substantially lower than that required by a fracture penetrating the same barrier from one side. Sensitivity studies of geologic conditions and operational parameters have also been performed to explore the feasibility of controlled fracture height. The interactions between hydraulic fractures, natural fractures, and geologic factors such as stress barriers in three dimensions are shown to be much more complex than in two dimensions. Although it is impossible to exhaust all the possible configurations, the ability of a 3D, fully coupled numerical model to naturally capture these processes is well-demonstrated.

A Peridynamics Model for the Propagation of Hydraulic Fractures in Heterogeneous, Naturally Fractured Reservoirs

2015 ◽  
Author(s):  
Hisanao Ouchi ◽  
Amit Katiyar ◽  
John T. Foster ◽  
Mukul M. Sharma
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
Two Dimensions ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Fracture Networks ◽  
Complex Fracture ◽  
Nonlocal Continuum Theory

Abstract A novel fully coupled hydraulic fracturing model based on a nonlocal continuum theory of peridynamics is presented and applied to the fracture propagation problem. It is shown that this modeling approach provides an alternative to finite element and finite volume methods for solving poroelastic and fracture propagation problems and offers some clear advantages. In this paper we specifically investigate the interaction between a hydraulic fracture and natural fractures. Current hydraulic fracturing models remain limited in their ability to simulate the formation of non-planar, complex fracture networks. The peridynamics model presented here overcomes most of the limitations of existing models and provides a novel approach to simulate and understand the interaction between hydraulic fractures and natural fractures. The model predictions in two-dimensions have been validated by reproducing published experimental results where the interaction between a hydraulic fracture and a natural fracture is controlled by the principal stress contrast and the approach angle. A detailed parametric study involving poroelasticity and mechanical properties of the rock is performed to understand why a hydraulic fracture gets arrested or crosses a natural fracture. This analysis reveals that the poroelasticity, resulting from high fracture fluid leak-off, has a dominant influence on the interaction between a hydraulic fracture and a natural fracture. In addition, the fracture toughness of the rock, the toughness of the natural fracture, and the shear strength of the natural fracture also affect the interaction between a hydraulic fracture and a natural fracture. Finally, we investigate the interaction of multiple completing fractures with natural fractures in two-dimensions and demonstrate the applicability of the approach to simulate complex fracture networks on a field scale.

Impact of Complex Fracture Networks on Rate Transient Behavior of Wells in Unconventional Reservoirs Based on Embedded Discrete Fracture Model

2021 ◽  
pp. 1-12
Author(s):  
Jiazheng Qin ◽  
Yingjie Xu ◽  
Yong Tang ◽  
Rui Liang ◽  
Qianhu Zhong ◽  
...  
Keyword(s):  
Flow Regimes ◽  
Natural Fracture ◽  
Fracture Model ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Fracture Networks ◽  
Discrete Fracture Model ◽  
Complex Fracture ◽  
Discrete Fracture ◽  
The Impact

Abstract It has recently been demonstrated that complex fracture networks (CFN) especially activated natural fractures (ANF) play an important role in unconventional reservoir development. However, traditional rate transient analysis (RTA) methods barely investigate the impact of CFN or ANF. Furthermore, the influence of CFN on flow regime is still ambiguous. Failure to consider these effects could lead to misdiagnosis of flow regimes and underestimation of original oil in place (OOIP). A novel numerical RTA method is therefore presented herein to improve the quality of reserves assessment. A new methodology is introduced. Propagating hydraulic fractures (HF) can generate different stress perturbations to allow natural fractures (NF) to fail, forming various ANF pattern. An embedded discrete fracture model (EDFM) of ANF is stochastically generated instead of local grid refinement (LGR) method to overcome the time-intensive computation time. These models are coupled with reservoir models using non-neighboring connections (NNCs). Results show that except for simplified models used in previous studies subjected to traditional concept of stimulated reservoir volume (SRV), in our study, the ANF region has been discussed to emphasis the impact of NF on simulation results. Henceforth, ANF could be only concentrated around the near-wellbore region, and it may also cover the whole simulation area. Obvious distinctions could be viewed for different kinds of ANF on diagnostic plots. Instead of SRV-dominated flow mentioned in previous studies, ANF-dominated flow developed in this work is shown to be more reasonable. Also, new flow regimes such as interference flow inside and outside activated natural fracture flow region (ANFR) are found. In summary, better evaluation of reservoir properties and reserves assessment such as OOIP are achieved based on our proposed model compared with conventional models. The novel RTA method considering CFN presented herein is an easy-to-apply numerical RTA technique that can be applied for reservoir and fracture characterization as well as OOIP assessment.

scholarly journals Numerical Simulation of Hydraulic Fracture Propagation in Coal Seams with Discontinuous Natural Fracture Networks

Processes ◽  
2018 ◽  
Vol 6 (8) ◽  
pp. 113 ◽  
Author(s):  
Shen Wang ◽  
Huamin Li ◽  
Dongyin Li
Keyword(s):  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
Fracture Network ◽  
Natural Fracture ◽  
Cohesive Element ◽  
Natural Fractures ◽  
Fracture Networks ◽  
Coal Seams ◽  
Hydraulic Fracture Network ◽  
Hydraulic Fracture Propagation

To investigate the mechanism of hydraulic fracture propagation in coal seams with discontinuous natural fractures, an innovative finite element meshing scheme for modeling hydraulic fracturing was proposed. Hydraulic fracture propagation and interaction with discontinuous natural fracture networks in coal seams were modeled based on the cohesive element method. The hydraulic fracture network characteristics, the growth process of the secondary hydraulic fractures, the pore pressure distribution and the variation of bottomhole pressure were analyzed. The improved cohesive element method, which considers the leak-off and seepage behaviors of fracturing liquid, is capable of modeling hydraulic fracturing in naturally fractured formations. The results indicate that under high stress difference conditions, the hydraulic fracture network is spindle-shaped, and shows a multi-level branch structure. The ratio of secondary fracture total length to main fracture total length was 2.11~3.62, suggesting that the secondary fractures are an important part of the hydraulic fracture network in coal seams. In deep coal seams, the break pressure of discontinuous natural fractures mainly depends on the in-situ stress field and the direction of natural fractures. The mechanism of hydraulic fracture propagation in deep coal seams is significantly different from that in hard and tight rock layers.

scholarly journals Numerical Simulation of the Influence of Natural Fractures on Hydraulic Fracture Propagation

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-12 ◽  
Author(s):  
Song Yaobin ◽  
Lu Weiyong ◽  
He Changchun ◽  
Bai Erhu
Keyword(s):  
Tensile Strength ◽  
Principal Stress ◽  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Stress Difference ◽  
Natural Fractures ◽  
Approach Angle ◽  
Hydraulic Fracture Propagation

According to the theory of plane mechanics involving the interaction of hydraulic and natural fractures, the law of hydraulic fracture propagation under the influence of natural fractures is verified using theoretical analysis and RFPA2D-Flow numerical simulation approaches. The shear and tensile failure mechanisms of rock are simultaneously considered. Furthermore, the effects of the approach angle, principal stress difference, tensile strength and length of the natural fracture, and elastic modulus and Poisson’s ratio of the reservoir on the propagation law of a hydraulic fracture are investigated. The following results are obtained: (1) The numerical results agree with the experimental data, indicating that the RFPA2D-Flow software can be used to examine the hydraulic fracture propagation process under the action of natural fractures. (2) In the case of a low principal stress difference and low approach angle, the hydraulic fracture likely causes shear failure along the tip of the natural fracture. However, under a high stress difference and high approach angle, the hydraulic fracture spreads directly through the natural fracture along the original direction. (3) When natural fractures with a low tensile strength encounter hydraulic fractures, the hydraulic fractures likely deviate and expand along the natural fractures. However, in the case of natural fractures with a high tensile strength, the natural fracture surface is closed, and the hydraulic fracture directly passes through the natural fracture, propagating along the direction of the maximum principal stress. (4) Under the same principal stress difference, a longer natural fracture corresponds to the easier initiation and expansion of a hydraulic fracture from the tip of the natural fracture. However, when the size of the natural fracture is small, the hydraulic fracture tends to propagate directly through the natural fracture. (5) A smaller elastic modulus and larger Poisson’s ratio of the reservoir result in a larger fracture initiation pressure. The presented findings can provide theoretical guidance regarding the hydraulic fracturing of reservoirs with natural fractures.

Case Study: 4D Coupled Reservoir/Geomechanics Simulation of a High-Pressure/High-Temperature Naturally Fractured Reservoir

SPE Journal ◽  
2018 ◽  
Vol 23 (05) ◽  
pp. 1518-1538 ◽  
Author(s):  
Xiangtong Yang ◽  
Yuanwei Pan ◽  
Wentong Fan ◽  
Yongjie Huang ◽  
Yang Zhang ◽  
...  
Keyword(s):  
Hydraulic Fracture ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Fracture System ◽  
Fractured Reservoir ◽  
Natural Fractures ◽  
Well Integrity ◽  
3D Geomechanical Model ◽  
Naturally Fractured ◽  
Reservoir Geomechanics

Summary The Keshen Reservoir is a naturally fractured, deep, tight sandstone gas reservoir under high tectonic stress. Because the reservoir matrix is very tight, the natural-fracture system is the main pathway for gas production. Meanwhile, stimulation is still required for most production wells to provide production rates that sufficiently compensate for the high cost of drilling and completing wells to access this deep reservoir. Large depletion (and related stress change) was expected during the course of the production of the field. The dynamic response of the reservoir and related risks, such as reduction of fracture conductivity, fault reactivation, and casing failure, would compromise the long-term productivity of the reservoir. To quantify the dynamic response of the reservoir and related risks, a 4D reservoir/geomechanics simulation was conducted for Keshen Reservoir by following an integrated work flow. The work started from systematic laboratory fracture-conductivity tests performed with fractured cores to measure conductivity vs. confining stress for both natural fractures and hydraulic fractures (with proppant placed in the fractures of the core samples). Natural-fracture modeling was conducted to generate a discrete-fracture network (DFN) to delineate spatial distribution of the natural-fracture system. In addition, hydraulic-fracture modeling was conducted to delineate the geometry of the hydraulic-fracture system for the stimulated wells. Then, a 3D geomechanical model was constructed by integrating geological, petrophysical, and geomechanical data, and both the DFN and hydraulic-fracture system were incorporated into the 3D geomechanical model. A 4D reservoir/geomechanics simulation was conducted through coupling with a reservoir simulator to predict variations of stress and strain of rock matrix as well as natural fractures and hydraulic fractures during field production. At each study-well location, a near-wellbore model was extracted from the full-field model, and casing and cement were installed to evaluate well integrity during production. The 4D reservoir/geomechanics simulation revealed that there would be a large reduction of conductivity for both natural fractures and hydraulic fractures, and some fractures with certain dip/dip azimuth will be reactivated during the course of field production. The induced-stress change will also compromise well integrity for those poorly cemented wellbores. The field-development plan must consider all these risks to ensure sustainable long-term production. The paper presents a 4D coupled geomechanics/reservoir-simulation study applied to a high-pressure/high-temperature (HP/HT) naturally fractured reservoir, which has rarely been published previously. The study adapted several new techniques to quantify the mechanical response of both natural fractures and hydraulic fractures, such as using laboratory tests to measure stress sensitivity of natural fractures, integrating DFN and hydraulic-fracture systems into 4D geomechanics simulation, and evaluating well integrity on both the reservoir scale and the near-wellbore scale.

Modeling of Hydraulic Fracture Network Propagation in Shale Gas Reservoirs

2014 ◽  
Author(s):  
Chong Hyun Ahn ◽  
Robert Dilmore ◽  
John Yilin Wang
Keyword(s):  
Shale Gas ◽  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
Fracture Network ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Gas Reservoirs ◽  
Complex Fracture ◽  
Shale Gas Reservoirs ◽  
Hydraulic Fracture Network

The most effective method for stimulating shale gas reservoirs is horizontal drilling with successful multi-stage hydraulic fracture treatments. Recent fracture diagnostic technologies have shown that complex fracture networks are commonly created in the field. The interaction between preexisting natural fractures and the propagating hydraulic fracture is a critical factor affecting the complex fracture network. However, many existing numerical models simulate only planar hydraulic fractures without considering the pre-existing fractures in the formation. The shale formations already contain a large number of natural fractures, so an accurate fracture propagation model needs to be developed to optimize the fracturing process. In this paper, we first understood the interaction between hydraulic and natural fractures. We then developed a new, coupled numerical model that integrates dynamic fracture propagation, reservoir flow simulation, and the interactions between hydraulic fractures and pre-existing natural fractures. By using the developed model, we conducted parametric studies to quantify the effects of rock toughness, stress anisotropy, and natural fracture spacing on the geometry and conductivities of the hydraulic fracture network. Lastly, we introduced new parmeters Fracture Network Index (FNI) and Width Anistropy (Wani) which may describe the characteristics of the fracture network in shale gas reservoirs. This new knowledge helps one understand and optimize the stimulation of shale gas reservoirs.

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.

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