scholarly journals Numerical simulation of horizontal well network fracturing in glutenite reservoir

2018 ◽  
Vol 73 ◽  
pp. 53
Author(s):  
Minhui Qi ◽  
Mingzhong Li ◽  
Yanchao Li ◽  
Tiankui Guo ◽  
Song Gao
Keyword(s):  
Numerical Simulation ◽  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Horizontal Well ◽  
Fracture Propagation ◽  
Simulation Method ◽  
Fracture Network ◽  
Fluid Viscosity ◽  
Coupled Flow ◽  
Hydraulic Fracture Propagation

Hydraulic fracturing is an economically effective technology developing the glutenite reservoirs, which have far stronger heterogeneity than the conventional sandstone reservoir. According to the field production experience of Shengli Oilfield, horizontal-well fracturing is more likely to develop a complex fractured network, which improves the stimulated volume of reservoir effectively. But the clear mechanism of horizontal-well hydraulic fracture propagation in the glutenite reservoirs is still not obtained, thus it is difficult to effectively carry out the design of fracturing plan. Based on the characteristics of the glutenite reservoirs, a coupled Flow-Stress-Damage (FSD) model of hydraulic fracture propagation is established. The numerical simulation of fracturing expansion in the horizontal well of the glutenite reservoir is conducted. It is shown that a square mesh-like fracture network is developed near the horizontal well in the reservoir with lower stress difference, in which fracture is more prone to propagate along the direction of the minimum principal stress as well. High fracturing fluids injection displacement and high fracturing fluid viscosity lead to the rise of static pressure of the fracture, which results in the rise of fracture complexity, and greater probability to deflect when encountering gravels. As the perforation density increases, the micro-fractures generated at each perforation gather together faster, and the range of the stimulated reservoir is also relatively large. For reservoirs with high gravel content, the complexity of fracture network and the effect of fracture communication are obviously increased, and the range of fracture deflection is relatively large. In the case of the same gravel distribution, the higher the tensile strength of the gravel, the greater fracture tortuosity and diversion was observed. In this paper, a simulation method of horizontal well fracture network propagation in the reservoirs is introduced, and the result provides the theoretical support for fracture network morphology prediction and plan design of hydraulic fracturing in the glutenite reservoir.

scholarly journals Numerical Investigation of Hydraulic Fracture Propagation Based on Cohesive Zone Model in Naturally Fractured Formations

Processes ◽  
2019 ◽  
Vol 7 (1) ◽  
pp. 28 ◽  
Author(s):  
Jianxiong Li ◽  
Shiming Dong ◽  
Wen Hua ◽  
Xiaolong Li ◽  
Xin Pan
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Cohesive Zone ◽  
Coupled Model ◽  
Fracture Propagation ◽  
Fracture Network ◽  
Zone Model ◽  
Naturally Fractured ◽  
Hydraulic Fracture Propagation ◽  
Multiple Cluster

Complex propagation patterns of hydraulic fractures often play important roles in naturally fractured formations due to complex mechanisms. Therefore, understanding propagation patterns and the geometry of fractures is essential for hydraulic fracturing design. In this work, a seepage–stress–damage coupled model based on the finite pore pressure cohesive zone (PPCZ) method was developed to investigate hydraulic fracture propagation behavior in a naturally fractured reservoir. Compared with the traditional finite element method, the coupled model with global insertion cohesive elements realizes arbitrary propagation of fluid-driven fractures. Numerical simulations of multiple-cluster hydraulic fracturing were carried out to investigate the sensitivities of a multitude of parameters. The results reveal that stress interference from multiple-clusters is responsible for serious suppression and diversion of the fracture network. A lower stress difference benefits the fracture network and helps open natural fractures. By comparing the mechanism of fluid injection, the maximal fracture network can be achieved with various injection rates and viscosities at different fracturing stages. Cluster parameters, including the number of clusters and their spacing, were optimal, satisfying the requirement of creating a large fracture network. These results offer new insights into the propagation pattern of fluid driven fractures and should act as a guide for multiple-cluster hydraulic fracturing, which can help increase the hydraulic fracture volume in naturally fractured reservoirs.

scholarly journals Experimental and Numerical Simulation Study of Hydraulic Fracture Propagation during Coalbed Methane Development

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-12
Author(s):  
Qingshan Ren ◽  
Yaodong Jiang ◽  
Pengpeng Wang ◽  
Guangjie Wu ◽  
Nima Noraei Danesh
Keyword(s):  
Numerical Simulation ◽  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Coalbed Methane ◽  
Fracture Propagation ◽  
Fractured Reservoir ◽  
Natural Fractures ◽  
Fracture Length ◽  
Coalbed Methane Reservoir ◽  
Hydraulic Fracture Propagation

The extraction of low-permeability coalbed methane (CBM) has the dual significance of energy utilization and safe mining. Understanding hydraulic fracturing mechanism is vital to successful development of CBM. Therefore, it is important to improve the law of hydraulic fracture propagation in coal and rigorously study the influencing factors. In this paper, laboratory experiments and numerical simulation methods were used to investigate the hydraulic fracture propagation law of coal in coalbed methane reservoir with natural fractures. The results show that the maximum and minimum horizontal in situ stress and the difference in stress significantly affect the direction of crack propagation. The elastic modulus of coal, the mechanical properties of natural fractures, and the injection rate can affect the fracture length, fracture width, and the amount of fracturing fluid injected. To ensure the effectiveness of hydraulic fracturing, a reservoir environment with a certain horizontal stress difference under specific reservoir conditions can ensure the increase of fractured reservoir and the controllability of fracture expansion direction. In order to increase the volume of fractured reservoir and fracture length, the pumping speed of fracturing fluid should not be too high. The existence of stress shadow effect causes the hydraulic fracture to propagate along the main fracture track, where the branch fracture cannot extend too far. Complex fractures are the main hydraulic fracture typology in coalbed methane reservoir with natural fractures. The results can provide a benchmark for optimal design of hydraulic fracturing in coalbed methane reservoirs.

Integration of Dynamic Microseismic Data With a True 3D Modeling of Hydraulic-Fracture Propagation in the Vaca Muerta Shale

SPE Journal ◽  
2017 ◽  
Vol 22 (06) ◽  
pp. 1714-1738 ◽  
Author(s):  
Mahdi Haddad ◽  
Jing Du ◽  
Sandrine Vidal-Gilbert
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
Natural Fracture ◽  
Zone Model ◽  
Fluid Viscosity ◽  
Fracture Intersection ◽  
Vaca Muerta ◽  
Hydraulic Fracture Propagation ◽  
Microseismic Events

Summary Microseismic mapping during the hydraulic-fracturing processes in the Vaca Muerta (VM) Shale in Argentina shows a group of microseismic events occurring at shallower depth and at later injection time, and they clearly deviate from the growing planar hydraulic fracture. This spatial and temporal behavior of these shallow microseismic events incurs some questions regarding the nature of these events and their connectivity to the hydraulic fracture. To answer these questions, in this article, we investigate these phenomena by use of a true 3D fracture-propagation-modeling tool along with statistical analysis on the properties of microseismic events. First, we propose a novel technique in Abaqus incorporating fracture intersections in true 3D hydraulic-fracture-propagation simulations by use of a pore-pressure cohesive zone model (CZM), which is validated by comparing our numerical results with the Khristianovic-Geertsma-de Klerk (KGD) solution (Khristianovic and Zheltov 1955; Geertsma and de Klerk 1969). The simulations fully couple slot flow in the fracture with poroelasticity in the matrix and continuum-based leakoff on the fracture walls, and honor the fracture-tip effects in quasibrittle shales. By use of this model, we quantify vertical-natural-fracture activation and fluid infiltration depending on reservoir depth, fracturing-fluid viscosity, mechanical properties of the natural-fracture cohesive layer, natural-fracture conductivity, and horizontal stress contrast. The modeling results demonstrate this natural-fracture activation in coincidence with the hydraulic-fracture-growth complexities at the intersection, such as height throttling, sharp aperture reduction after the intersection, and multibranching at various heights and directions. Finally, we investigate the hydraulic-fracture intersection with a natural fracture in the multilayer VM Shale. We infer the natural-fracture location and orientation from the microseismic-events map and formation microimager log in a nearby vertical well, respectively. We integrate the other field information such as mechanical, geological, and operational data to provide a realistic hydraulic-fracturing simulation in the presence of a natural fracture. Our 3D fracturing simulations equipped with the new fracture-intersection model rigorously simulate the growth of a realistic hydraulic-connection path toward the natural fracture at shallower depths, which was in agreement with our microseismic observations.

Advancements in Step Down Tests to Guide Perforation Cluster Design and Limited Entry Pressure Intensities - Learnings from Field Tests in Multiple Basins

2021 ◽  
Author(s):  
Somnath Mondal ◽  
Min Zhang ◽  
Paul Huckabee ◽  
Gustavo Ugueto ◽  
Raymond Jones ◽  
...  
Keyword(s):  
Pressure Drop ◽  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
Field Tests ◽  
Pressure Drops ◽  
Wellbore Pressure ◽  
Hydraulic Fracture Propagation ◽  
Step Down ◽  
Cluster Design

Abstract This paper presents advancements in step-down-test (SDT) interpretation to better design perforation clusters. The methods provided here allow us to better estimate the pressure drop in perforations and near-wellbore tortuosity in hydraulic fracturing treatments. Data is presented from field tests from fracturing stages with different completion architectures across multiple basins including Permian Delaware, Vaca Muerta, Montney, and Utica. The sensitivity of near-wellbore pressure drops and perforation size on stimulation distribution effectiveness in plug-and-perf (PnP) treatments is modeled using a coupled hydraulic fracturing simulator. This advanced analysis of SDT data enables us to improve stimulation distribution effectiveness in multi-cluster or multiple entry completions. This analysis goes much further than the methodology presented in URTeC2019-1141 and additional examples are presented to illustrate its advantages. In a typical SDT, the injection flowrate is reduced in four or five abrupt decrements or "steps", each with a duration long enough for the rate and pressure to stabilize. The pressure-rate response is used to estimate the magnitude of perforation efficiency and near-wellbore tortuosity. In this paper, two SDTs with clean fluids were conducted in each stage - one before and another after proppant slurry was injected. SDTs were conducted in cemented single-point entry (cSPE) sleeves, which present a unique opportunity to measure only near-wellbore tortuosity using bottom-hole pressure gauge at sleeve depth, negligible perforation pressure drops, and less uncertainty in interpretation. SDTs were conducted in PnP stages in multiple unconventional basins. The results from one set of PnP stages with optic fiber distributed sensing were modeled with a hydraulic fracturing simulator that combines wellbore proppant transport, perforation size growth, near-wellbore pressure drop, and hydraulic fracture propagation. Past SDT analysis assumed that the pressure drop due to near-wellbore tortuosity is proportional to the flow rate raised to an exponent, β = 0.5, which typically overestimates perforation friction from SDTs. Theoretical derivations show that β is related to the geometry and flow type in the near-wellbore region. Results show that initial β (before proppant slurry) is typically around 0.5, but the final value of β (after proppant slurry) is approximately 1, likely due to the erosion of near-wellbore tortuosity by the proppant slurry. The new methodology incorporates the increase in β due proppant slurry erosion. Hydraulic fracturing modeling, calibrated with optic fiber data, demonstrates that the stimulation distribution effectiveness must consider the interdependence of proppant segregation in the wellbore, perforation erosion, and near-wellbore tortuosity. An improved methodology is presented to quantify the magnitude of perforation and near-wellbore tortuosity related pressure drops before and after pumping of proppant slurry in typical PnP hydraulic fracture stimulations. The workflow presented here shows how the uncertainties in the magnitude of near-wellbore complexity and perforation size, along with uncertainties in hydraulic fracture propagation parameters, can be incorporated in perforation cluster design.

Sign in / Sign up

Export Citation Format

Share Document