scholarly journals Efficient Modeling of Hydraulic Fractures with Diamond Boundary in Shale Gas Reservoirs

Lithosphere ◽  
2021 ◽  
Vol 2021 (Special 4) ◽  
Author(s):  
Mingyi Gao ◽  
Wen Zhou ◽  
Jian Zhang ◽  
Cheng Chang ◽  
Chuxi Liu ◽  
...  
Keyword(s):  
Shale Gas ◽  
Hydraulic Fracture ◽  
History Matching ◽  
Total Surface Area ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Well Performance ◽  
Production Forecast ◽  
Discrete Fracture Model ◽  
Discrete Fracture

Abstract The effects of hydraulic fractures with complex boundaries on the well performance of a shale gas well, considering a more realistic corner point geological model, have rarely been studied previously. In this study, the nonintrusive embedded discrete fracture model (EDFM) method was employed to investigate the effects of different boundary shapes of hydraulic fracture, coupling a network of sophisticated natural fractures discrete fracture network (DFN) on well performance. First, by implementing the powerful EDFM technology, concepts of two categories (rectangle and diamond) of hydraulic fracture with different boundaries were designed. Next, the geometric equations defining vertices of multiple rectangular- or diamond-shaped hydraulic fractures in arbitrary coordinate systems were derived. Subsequently, the horizontal well with multistaged hydraulic fractures and sophistically oriented 3D natural fractures was inputted into the reservoir model to perform history matching. After history matching, the results were further analyzed to compare the production forecast from the two categories. The results show that 20-year cumulative gas productions for rectangle- and diamond-shaped fractures are approximately 1.237×108 m3 and 1.486×108 m3, respectively. In other words, the diamond category can produce 20.1% more gas than the rectangle category. For cumulative water production, the diamond category produces 3.8×104 m3, as against the 3.0×104 m3 produced by the rectangle category (or 26.7% more). This implies that the diamond-shaped fractures have the potential to reach the far field region of the reservoir away from the wellbore. This means that more intersections with natural fractures DFN can be achieved, and more drainage area is unlocked. The visualization of pressure distributions and drainage volume was easily shown, and these results further confirm that the extent of fluid drainage by the diamond fracture is larger compared to that by the rectangular fracture given the same total surface area.

scholarly journals Investigation of the Effect of Natural Fractures on Multiple Shale-Gas Well Performance Using Non-Intrusive EDFM Technology

Energies ◽  
2019 ◽  
Vol 12 (5) ◽  
pp. 932 ◽  
Author(s):  
Wei Yu ◽  
Xiaohu Hu ◽  
Malin Liu ◽  
Weihong Wang
Keyword(s):  
Shale Gas ◽  
History Matching ◽  
Natural Fracture ◽  
Fracture Density ◽  
Natural Fractures ◽  
Well Performance ◽  
Two Phase ◽  
Gas Well ◽  
Discrete Fracture Model ◽  
Well Spacing

The influence of complex natural fractures on multiple shale-gas well performance with varying well spacing is poorly understood. It is difficult to apply the traditional local grid refinement with structured or unstructured gridding techniques to accurately and efficiently handle complex natural fractures. In this study, we introduced a powerful non-intrusive embedded discrete fracture model (EDFM) technology to overcome the limitations of exiting methods. Through this unique technology, complex fracture configurations can be easily and explicitly embedded into structured matrix blocks. We set up a field-scale two-phase reservoir model to history match field production data and predict long-term recovery from Marcellus. The effective fracture properties were determined thorough history matching. In addition, we extended the single-well model to include two horizontal wells with and without including natural fractures. The effects of different numbers of natural fractures on two-well performance with varying well spacing of 200 m, 300 m, and 400 m were examined. The simulation results illustrate that gas productivity almost linearly increases with the number of two-set natural fractures. Furthermore, the difference of well performance between different well spacing increases with an increase in natural fracture density. A larger well spacing is preferred for economically developing the shale-gas reservoirs with a larger natural fracture density. The findings of this study provide key insights into understanding the effect of natural fractures on well performance and well spacing optimization.

scholarly journals The Application of Integrated Assisted History Matching and Embedded Discrete Fracture Model Workflow for Well Spacing Optimization in Shale Gas Reservoirs with Complex Natural Fractures

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-14
Author(s):  
Qiwei Li ◽  
Jianfa Wu ◽  
Cheng Chang ◽  
Hongzhi Yang ◽  
Chuxi Liu ◽  
...  
Keyword(s):  
Shale Gas ◽  
Reservoir Simulation ◽  
History Matching ◽  
Fracture Model ◽  
Natural Fractures ◽  
Gas Reservoirs ◽  
Discrete Fracture Model ◽  
Shale Gas Reservoirs ◽  
Well Spacing ◽  
Discrete Fracture

An appropriate well spacing plan is critical for the economic development of shale gas reservoirs. The biggest challenge for well spacing optimization is interpreting the subsurface uncertainties associated with hydraulic and natural fractures. Another challenge is the existence of complex natural fractures. This work applied an integrated well spacing optimization workflow in shale gas reservoirs of the Sichuan Basin in China with both hydraulic and natural fractures. The workflow consists of five components: data preparation, reservoir simulation, estimated ultimate recovery (EUR) analysis, economic calculation, and well spacing optimization. Firstly, the multiple realizations of thirteen uncertain parameters of matrix and fractures, including matrix permeability and porosity, three relative permeability parameters, hydraulic fracture height, half-length, width, conductivity, water saturation, and natural fracture number, length, and conductivity, were captured by the assisted history matching (AHM). The fractures were modeled by the embedded discrete fracture model (EDFM) accurately and efficiently. Then, 84 AHM solutions combining with five well spacing scenarios from 517 ft to 1550 ft would generate 420 simulation cases. After reservoir simulation of these 420 cases, we forecasted the long-term gas production for each well spacing scenario. Gas EUR degradation and well interference would imply the critical well spacing. The net present value (NPV) for all scenarios would be calculated and trained by K -nearest neighbors (KNN) proxy to better understand the relationship between well spacing and NPV. In this study, the optimum well spacing was determined as 793 ft, corresponding with a maximum NPV of 18 million USD, with the contribution of hydraulic fractures and natural fractures.

Efficient Modeling of Unconventional Well Performance with Millions of Natural and Hydraulic Fractures Using Embedded Discrete Fracture Model EDFM

2021 ◽  
Author(s):  
Wei Yu ◽  
Anuj Gupta ◽  
Ravimadhav N. Vaidya ◽  
Kamy Sepehrnoori
Keyword(s):  
Fractured Reservoirs ◽  
Horizontal Wells ◽  
Development Planning ◽  
Fracture Model ◽  
Computational Time ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Well Performance ◽  
Discrete Fracture Model ◽  
Discrete Fracture

Abstract The complexity of dynamic modeling for naturally fractured reservoirs has increased in recent years to incorporate more data and physics, as well as to handle advanced completion designs and development scenarios. While these complex models can provide more insight to difficult problems, they come with higher computational costs. Such a limitation prohibits an asset team from working with a large number of well/fracture scenarios that correctly represent geological uncertainty. This study presents a powerful non-intrusive Embedded Discrete Fracture Model (EDFM) method to efficiently handle millions of natural and hydraulic fractures with hundreds of horizontal wells, which has never been modeled in the literature. Specifically, we built a 3D geological model using a black oil reservoir simulator with 100 square miles in the horizontal area and 11 layers of 165 ft thickness. The total number of matrix cells without considering fractures is over 3 million. In total, 400 horizontal wells with well length of 6000 ft were modeled in two target layers. Each layer contains 200 wells. Each well has 112 hydraulic fractures with cluster spacing of 50 ft. The total number of hydraulic fractures is 44,800. In addition, we generated three cases with 10K, 100K and 1 million 3D natural fractures with dip angle from 70 to 90 degrees. For the case with 1 million natural fractures, the total number of cells is over 42 million. Well performance for the field example, with and without natural fractures, was investigated. This work adds significant value to the well and fracture spacing optimization process during field development planning. The non-intrusive EDFM method has been proven to be an efficient fracture modeling tool for simulating million-level complex hydraulic/natural fractures, which significantly improves accuracy and reduces computational time.

Fully Coupled Hydromechanical Simulation of Hydraulic Fracturing in Three-Dimensional Discrete Fracture Networks

2015 ◽  
Author(s):  
Mark W. McClure ◽  
Mohsen Babazadeh ◽  
Sogo Shiozawa ◽  
Jian Huang
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Three Dimensional ◽  
Hydraulic Fractures ◽  
Fracture Aperture ◽  
Natural Fractures ◽  
Fracture Networks ◽  
Field Scale ◽  
Discrete Fracture Networks ◽  
Discrete Fracture

Abstract We developed a hydraulic fracturing simulator that implicitly couples fluid flow with the stresses induced by fracture deformation in large, complex, three-dimensional discrete fracture networks. The simulator can describe propagation of hydraulic fractures and opening and shear stimulation of natural fractures. Fracture elements can open or slide, depending on their stress state, fluid pressure, and mechanical properties. Fracture sliding occurs in the direction of maximum resolved shear stress. Nonlinear empirical relations are used to relate normal stress, fracture opening, and fracture sliding to fracture aperture and transmissivity. Fluid leakoff is treated with a semianalytical one-dimensional leakoff model that accounts for changing pressure in the fracture over time. Fracture propagation is treated with linear elastic fracture mechanics. Non-Darcy pressure drop in the fractures due to high flow rate is simulated using Forchheimer's equation. A crossing criterion is implemented that predicts whether propagating hydraulic fractures will cross natural fractures or terminate against them, depending on orientation and stress anisotropy. Height containment of propagating hydraulic fractures between bedding layers can be modeled with a vertically heterogeneous stress field or by explicitly imposing hydraulic fracture height containment as a model assumption. The code is efficient enough to perform field-scale simulations of hydraulic fracturing with a discrete fracture network containing thousands of fractures, using only a single compute node. Limitations of the model are that all fractures must be vertical, the mechanical calculations assume a linearly elastic and homogeneous medium, proppant transport is not included, and the locations of potentially forming hydraulic fractures must be specified in advance. Simulations were performed of a single propagating hydraulic fracture with and without leakoff to validate the code against classical analytical solutions. Field-scale simulations were performed of hydraulic fracturing in a densely naturally fractured formation. The simulations demonstrate how interaction with natural fractures in the formation can help explain the high net pressures, relatively short fracture lengths, and broad regions of microseismicity that are often observed in the field during stimulation in low permeability formations, and which are not predicted by classical hydraulic fracturing models. Depending on input parameters, our simulations predicted a variety of stimulation behaviors, from long hydraulic fractures with minimal leakoff into surrounding fractures to broad regions of dense fracturing with a branching network of many natural and newly formed fractures.

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.

Fully Coupled Hydromechanical Simulation of Hydraulic Fracturing in 3D Discrete-Fracture Networks

SPE Journal ◽  
2016 ◽  
Vol 21 (04) ◽  
pp. 1302-1320 ◽  
Author(s):  
Mark W. McClure ◽  
Mohsen Babazadeh ◽  
Sogo Shiozawa ◽  
Jian Huang
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Fluid Pressure ◽  
Hydraulic Fractures ◽  
Fracture Aperture ◽  
Natural Fractures ◽  
Fracture Networks ◽  
Field Scale ◽  
Discrete Fracture Networks ◽  
Discrete Fracture

Summary We developed a hydraulic-fracturing simulator that implicitly couples fluid flow with the stresses induced by fracture deformation in large, complex, 3D discrete-fracture networks (DFNs). The code is efficient enough to perform field-scale simulations of hydraulic fracturing in DFNs containing thousands of fractures, without relying on distributed-memory parallelization. The simulator can describe propagation of hydraulic fractures and opening and shear stimulation of natural fractures. Fracture elements can open or slide, depending on their stress state, fluid pressure, and mechanical properties. Fracture sliding occurs in the direction of maximum resolved shear stress. Nonlinear empirical equations are used to relate normal stress, fracture opening, and fracture sliding to fracture aperture and transmissivity. Fluid leakoff is treated with a semianalytical 1D leakoff model that accounts for changing pressure in the fracture over time. Fracture propagation is modeled with linear-elastic fracture mechanics. The Forchheimer equation (Forchheimer 1901) is used to simulate non-Darcy pressure drop in the fractures because of high flow rate. A crossing criterion is implemented that predicts whether propagating hydraulic fractures will cross natural fractures or terminate against them, depending on orientation and stress anisotropy. Height containment of propagating hydraulic fractures between bedding layers can be modeled with a vertically heterogeneous stress field or by explicitly imposing hydraulic-fracture-height containment as a model assumption. Limitations of the model are that all fractures must be vertical; the mechanical calculations assume a linearly elastic and homogeneous medium; proppant transport is not included; and the locations of potentially forming hydraulic fractures must be specified in advance. Simulations were performed of a single propagating hydraulic fracture with and without leakoff to validate the code against classical analytical solutions. Field-scale simulations were performed of hydraulic fracturing in a densely naturally fractured formation. The simulations demonstrate how interaction with natural fractures in the formation can help explain the high net pressures, relatively short fracture lengths, and broad regions of microseismicity that are often observed in the field during stimulation in low-permeability formations, and that are not predicted by classical hydraulic-fracturing models. Depending on input parameters, our simulations predicted a variety of stimulation behaviors, from long hydraulic fractures with minimal leakoff into surrounding fractures to broad regions of dense fracturing with a branching network of many natural and newly formed fractures.

scholarly journals History Matching and Forecast of Shale Gas Production Considering Hydraulic Fracture Closure

Energies ◽  
2019 ◽  
Vol 12 (9) ◽  
pp. 1634 ◽  
Author(s):  
Juhyun Kim ◽  
Youngjin Seo ◽  
Jihoon Wang ◽  
Youngsoo Lee
Keyword(s):  
Shale Gas ◽  
Hydraulic Fracture ◽  
History Matching ◽  
Gas Flow ◽  
Fluid Pressure ◽  
Gas Production ◽  
Hydraulic Fractures ◽  
Gas Reservoirs ◽  
Shale Gas Reservoirs ◽  
Fracture Closure

Most shale gas reservoirs have extremely low permeability. Predicting their fluid transport characteristics is extremely difficult due to complex flow mechanisms between hydraulic fractures and the adjacent rock matrix. Recently, studies adopting the dynamic modeling approach have been proposed to investigate the shape of the flow regime between induced and natural fractures. In this study, a production history matching was performed on a shale gas reservoir in Canada’s Horn River basin. Hypocenters and densities of the microseismic signals were used to identify the hydraulic fracture distributions and the stimulated reservoir volume. In addition, the fracture width decreased because of fluid pressure reduction during production, which was integrated with the dynamic permeability change of the hydraulic fractures. We also incorporated the geometric change of hydraulic fractures to the 3D reservoir simulation model and established a new shale gas modeling procedure. Results demonstrate that the accuracy of the predictions for shale gas flow improved. We believe that this technique will enrich the community’s understanding of fluid flows in shale gas reservoirs.

scholarly journals PARAMETER PREDICTION OF HYDRAULIC FRACTURE FOR TIGHT RESERVOIR BASED ON MICRO-SEISMIC AND HISTORY MATCHING

Fractals ◽  
2018 ◽  
Vol 26 (02) ◽  
pp. 1840009 ◽  
Author(s):  
KAI ZHANG ◽  
XIAOPENG MA ◽  
YANLAI LI ◽  
HAIYANG WU ◽  
CHENYU CUI ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
History Matching ◽  
Seismic Source ◽  
Fracture Network ◽  
Distribution Area ◽  
Hydraulic Fractures ◽  
Discrete Fracture Model ◽  
Tight Reservoir ◽  
Seismic Source Location

Hydraulic fracturing is an important measure for the development of tight reservoirs. In order to describe the distribution of hydraulic fractures, micro-seismic diagnostic was introduced into petroleum fields. Micro-seismic events may reveal important information about static characteristics of hydraulic fracturing. However, this method is limited to reflect the distribution area of the hydraulic fractures and fails to provide specific parameters. Therefore, micro-seismic technology is integrated with history matching to predict the hydraulic fracture parameters in this paper. Micro-seismic source location is used to describe the basic shape of hydraulic fractures. After that, secondary modeling is considered to calibrate the parameters information of hydraulic fractures by using DFM (discrete fracture model) and history matching method. In consideration of fractal feature of hydraulic fracture, fractal fracture network model is established to evaluate this method in numerical experiment. The results clearly show the effectiveness of the proposed approach to estimate the parameters of hydraulic fractures.

An Integrated Assisted History Matching and Embedded Discrete Fracture Model Workflow for Well Spacing Optimization in Shale Gas Reservoirs

2021 ◽  
pp. 1-29
Author(s):  
Qiwei Li ◽  
Rui Yong ◽  
Jianfa Wu ◽  
Cheng Chang ◽  
Chuxi Liu ◽  
...  
Keyword(s):  
Shale Gas ◽  
History Matching ◽  
Essential Element ◽  
Fracture Model ◽  
Gas Reservoirs ◽  
Discrete Fracture Model ◽  
Shale Gas Reservoirs ◽  
Well Spacing ◽  
Discrete Fracture ◽  
Assisted History Matching

Abstract Optimum well spacing is an essential element for the economic development of shale gas reservoirs. We present an integrated assisted history matching (AHM) and embedded discrete fracture model (EDFM) workflow for well spacing optimization by considering multiple uncertainty realizations and economic analysis. This workflow is applied in shale gas reservoirs of the Sichuan Basin in China. Firstly, we applied the AHM to calibrate ten matrix and fracture uncertain parameters using a real shale-gas well, including matrix permeability, matrix porosity, three relative permeability parameters, fracture height, fracture half-length, fracture width, fracture conductivity, and fracture water saturation. There are 71 history matching solutions obtained to quantify their posterior distributions. Integrating these uncertainty realizations with five well spacing scenarios, which are 517 ft, 620 ft, 775 ft, 1030 ft, and 1550 ft, we generated 355 cases to perform production simulations using the EDFM method coupled with a reservoir simulator. Then, P10, P50, and P90 values of gas estimated ultimate recovery (EUR) for different well spacing scenarios were determined. Additionally, the degradation of EUR with and without well interference was analyzed. Next, we calculated the NPVs of all simulation cases and trained the K-Nearest Neighbors (KNN) proxy, which describes the relationship between the NPV and all uncertain matrix and fracture parameters and varying well spacing. After that, the KNN proxy was used to maximize the NPV under the current operation cost and natural gas price. Finally, the maximum NPV of 3 million USD with well spacing of 766 ft was determined.

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.

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