scholarly journals A New Method and Application of Full 3D Numerical Simulation for Hydraulic Fracturing Horizontal Fracture

Energies ◽  
2018 ◽  
Vol 12 (1) ◽  
pp. 48 ◽  
Author(s):  
Bing Xu ◽  
Yikun Liu ◽  
Yumei Wang ◽  
Guang Yang ◽  
Qiannan Yu ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Pressure Distribution ◽  
Three Dimensional ◽  
Initial Pressure ◽  
Fluid Viscosity ◽  
Fracturing Fluid ◽  
Horizontal Fracture ◽  
Initial Fracture ◽  
Net Pressure ◽  
Fracture Height

The numerical simulation of hydraulic fracturing fracture propagation is the core content of hydraulic fracturing design and construction. Its simulation results directly affect the effect of fracturing, and can effectively guide the fracturing construction plan and reduce the construction risk. At present, two-dimensional or quasi-three-dimensional models are mainly used, but most of them are used to simulate the vertical fracture of hydraulic fracturing. There are errors in the application process. In this paper, a three-dimensional mathematical model, including an elastic rock mechanics equation and a material flow continuity equation, is established to simulate horizontal fracture propagation in shallow reservoirs. The emphasis of this paper is to propose a new method for solving equations. The basic idea of the iteration method has been proposed by previous scholars: Firstly, assuming that the initial pressure of each point in the fracture is uniform, the fracture height of each initial point can be obtained by using Equation (20). Using the initial height values, the pressure values at each point of continuous variation are calculated by Equation (16), and then the new fracture height values are obtained by Equation (20). Because of the equal initial pressure, this method leads to too many iterations in the later stages, which makes the calculation more complicated. In this paper, a new Picca iteration method is proposed. The iteration parameters are changed sequentially. Firstly, the distribution value of fracture height is assumed. Then, the pressure distribution value is calculated according to Equation (16). Then, the new distribution value of fracture height is obtained by bringing the obtained pressure distribution value into Equation (20). Then, the new distribution value of the fracture height is calculated according to Equation (16). The pressure distribution value completes an iteration process until the iteration satisfies the convergence condition. In addition, Sneddon’s model is introduced into the hypothesis of fracture height to obtain the maximum fracture height and assume that the initial fracture profile is a parabola. Finally, the proposed method can rapidly improve the convergence rate. Next, on the basis of investigating the solutions of previous equations, the Galerkin finite element method is used to solve the above equations. The new Picard iteration sequence method is applied to solve the height and pressure at different points in the fracture. By calculating the stress intensity factor, we can judge whether the fracture continues to extend or not, and then simulate the full three-dimensional horizontal fracture of the hydraulic fracturing expansion process. The infiltration process of three types of oil reservoirs in Daqing Changyuan oilfield is simulated. The results show that during the initial fracture stage, the radius and height of fractures increase rapidly, and the rate of increase slows down with the increase of construction time. The height and net pressure of each point in the fracture are unequal. The height and net pressure of the fracture in the wellbore reach the maximum, and gradually decrease to the front of the fracture. Compared with conventional fracturing, the fracturing-flooding percolation process has the characteristics of short fracture-making and large vertical percolation distance, which can greatly increase the swept volume of flooding fluid and thus enhance oil recovery. With the increase in the rock modulus of elasticity, the radius of fractures decreases and the height of fractures increases. With the increase in construction displacement, the radius of fractures hardly changes, the height of fractures increases, and the vertical infiltration distance of the fractures increases. It is suggested that the construction displacement should be 4.0 m3/min. In the range of fracturing fluid viscosity in the studied block, with the change of fracturing fluid viscosity, the change of fracture radius and height is not obvious. In order to further increase sweep volume, the fracturing fluid viscosity should be further reduced.

scholarly journals A Novel Hydraulic Fracturing Method Based on the Coupled CFD-DEM Numerical Simulation Study

2020 ◽  
Vol 10 (9) ◽  
pp. 3027
Author(s):  
Cong Lu ◽  
Li Ma ◽  
Zhili Li ◽  
Fenglan Huang ◽  
Chuhao Huang ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Hydraulic Fracturing ◽  
Variable Viscosity ◽  
Oil Reservoirs ◽  
Fluid Viscosity ◽  
Low Density ◽  
Fracturing Fluid ◽  
Proppant Transport ◽  
Fracturing Fluids ◽  
Transport Experiment

For the development of tight oil reservoirs, hydraulic fracturing employing variable fluid viscosity and proppant density is essential for addressing the problems of uneven placement of proppants in fractures and low propping efficiency. However, the influence mechanisms of fracturing fluid viscosity and proppant density on proppant transport in fractures remain unclear. Based on computational fluid dynamics (CFD) and the discrete element method (DEM), a proppant transport model with fluid–particle two-phase coupling is established in this study. In addition, a novel large-scale visual fracture simulation device was developed to realize the online visual monitoring of proppant transport, and a proppant transport experiment under the condition of variable viscosity fracturing fluid and proppant density was conducted. By comparing the experimental results and the numerical simulation results, the accuracy of the proppant transport numerical model was verified. Subsequently, through a proppant transport numerical simulation, the effects of fracturing fluid viscosity and proppant density on proppant transport were analyzed. The results show that as the viscosity of the fracturing fluid increases, the length of the “no proppant zone” at the front end of the fracture increases, and proppant particles can be transported further. When alternately injecting fracturing fluids of different viscosities, the viscosity ratio of the fracturing fluids should be adjusted between 2 and 5 to form optimal proppant placement. During the process of variable proppant density fracturing, when high-density proppant was pumped after low-density proppant, proppants of different densities laid fractures evenly and vertically. Conversely, when low-density proppant was pumped after high-density proppant, the low-density proppant could be transported farther into the fracture to form a longer sandbank. Based on the abovementioned observations, a novel hydraulic fracturing method is proposed to optimize the placement of proppants in fractures by adjusting the fracturing fluid viscosity and proppant density. This method has been successfully applied to more than 10 oil wells of the Bohai Bay Basin in Eastern China, and the average daily oil production per well increased by 7.4 t, significantly improving the functioning of fracturing. The proppant settlement and transport laws of proppant in fractures during variable viscosity and density fracturing can be efficiently revealed through a visualized proppant transport experiment and numerical simulation study. The novel fracturing method proposed in this study can significantly improve the hydraulic fracturing effect in tight oil reservoirs.

scholarly journals Numerical Simulation Study on Propagation of Initial Microcracks in Cement Sheath Body during Hydraulic Fracturing Process

Energies ◽  
2020 ◽  
Vol 13 (5) ◽  
pp. 1260
Author(s):  
Yuqiang Xu ◽  
Yan Yan ◽  
Shenqi Xu ◽  
Zhichuan Guan
Keyword(s):  
Elastic Modulus ◽  
Hydraulic Fracturing ◽  
Internal Pressure ◽  
Element Model ◽  
Fluid Viscosity ◽  
Fracturing Fluid ◽  
Zone Method ◽  
Geological Conditions ◽  
Fracturing Process ◽  
Cement Sheath

Microcracks caused by perforating operations in a cement sheath body and interface have the potential to further expand or even cause crossflow during hydraulic fracturing. Currently, there are few quantitative studies on the propagation of initial cement-body microcracks. In this paper, a three-dimensional finite element model for the propagation of initial microcracks of the cement sheath body along the axial and circumferential directions during hydraulic fracturing was proposed based on the combination of coupling method of fluid–solid in porous media and the Cohesive Zone Method. The influence of reservoir geological conditions, the mechanical properties of a casing-cement sheath-formation system, and fracturing constructions in the propagation of initial axial microcracks of a cement sheath body was quantitatively analyzed. It can be concluded that the axial extension length of microcracks increased with the increase of elastic modulus of the cement sheath and formation, the flow rate of fracturing fluid, and casing internal pressure, and decreased with the increase of the cement sheath tensile strength and ground stress. The elastic modulus of the cement sheath had a greater influence on the expansion of axial cracks than the formation elastic modulus and casing internal pressure. The effect of fracturing fluid viscosity on the crack expansion was negligible. In order to effectively slow the expansion of the cement sheath body crack, the elastic modulus of the cement sheath can be appropriately reduced to enhance its toughness under the premise of ensuring sufficient strength of the cement sheath.

scholarly journals A parametric study of hydraulic fracturing interference between fracture clusters and stages based on numerical modeling

2020 ◽  
pp. 014459872095325
Author(s):  
Ang Chen ◽  
Xuyang Guo ◽  
Huiyong Yu ◽  
Lei Huang ◽  
Shanzhi Shi ◽  
...  
Keyword(s):  
Numerical Modeling ◽  
Hydraulic Fracturing ◽  
Horizontal Wells ◽  
Hydraulic Fractures ◽  
Fluid Viscosity ◽  
Shale Oil ◽  
Fracturing Fluid ◽  
Multi Stage ◽  
Study Results ◽  
Stress Contrast

Shale oil reservoirs are usually developed by horizontal wells completed with multi-stage hydraulic fractures. The fracture interference between clusters in a single stage and between consecutive stages has an impact on the stimulation quality in terms of fracture geometries and fracture widths. This study introduces a non-planar hydraulic fracture model based on the extended finite element method and its use in quantifying the effects of relevant parameters on multi-stage fracture quality in a realistic shale oil scenario. The numerical model is validated with field diagnostics based on vertical seismic profiling. Relevant parameters including stress contrast, fracturing fluid viscosity, cluster density, and fracturing in consecutive stages are quantitatively analyzed in the numerical study. Results show that effects of stress contrast on fracture quality are greater than those of fracturing fluid viscosity, while the effects are more significant in outer fractures instead of the inner fracture. Denser cluster design leads to greater inhibition for the growth of inner fractures which eventually divert them transversely. In fracturing for consecutive stages, the opening of fractures in the subsequent stages is inhibited and the fracture geometries are also altered by the inter-stage interference caused by the previous stage. Based on field data and numerical modeling, this study identifies key parameters and quantifies their effects on inter-fracture and inter-stage interference in multi-stage hydraulic fracturing in horizontal wells.

Part-Circular Cracks at Various Openings Under Complex Loading Conditions

1979 ◽  
Vol 101 (4) ◽  
pp. 270-275 ◽  
Author(s):  
S. K. Bhandari ◽  
B. Barrachin ◽  
J. L. Picou
Keyword(s):  
Pressure Distribution ◽  
Three Dimensional ◽  
Initial Pressure ◽  
Circular Crack ◽  
Complex Loading ◽  
Loading Conditions ◽  
Geometry Problem ◽  
Corner Cracks ◽  
The Given ◽  
Circular Cracks

It is shown that the problem of evaluating the stress-intensity factor of a part-circular crack at the base of any through opening in a three-dimensional solid under general external planer loading conditions can be reduced to the resolution of three problems: 1) Analysis of the three-dimensional uncracked solid with the given opening shape under given loading conditions; 2) analysis of a two-dimensional solid with the given opening shape and a line crack under the given loading conditions; 3) analysis of a semi-infinite solid with the given crack shape under uniform stress. In fact, the given problem, identical to that of a pressurized crack at the edge of an opening, is reduced to the solution of an embedded circular crack with suitable pressure distribution which takes into account the presence of the opening. This pressure distribution is postulated as a product of initial pressure due to the application of external load on the uncracked geometry (Problem 1) with a function resulting from the analysis of a 2-D problem (Problem 2). Finally, the K values calculated using this modified pressure distribution on the circular crack, are corrected for the 3-D nature of the crack front through the solution of Problem 3. The methodology has been applied to part-circular cracks at elliptical openings in a 3-D solid under traction and moment loading. The method has been extended to treat corner cracks in quarter solids. A circular crack at a BWR-nozzle corner has been treated as an illustrative example. Finally, some generalizations of the method have been suggested.

Three-Dimensional Hydraulic Fracture Propagation in the Presence of Stress Variations

1983 ◽  
Vol 23 (06) ◽  
pp. 870-878 ◽  
Author(s):  
Ian D. Palmer ◽  
H.B. Carroll
Keyword(s):  
Boundary Condition ◽  
Hydraulic Fracture ◽  
Three Dimensional ◽  
Fracture Propagation ◽  
Rock Properties ◽  
Vertical Fracture ◽  
Hydraulic Fracture Propagation ◽  
Net Pressure ◽  
Fracture Height ◽  
Stress Contrast

Abstract Models of three-dimensional (3D) fracture propagation are being developed to study the effect of variations of stress and rock properties on fracture height and bottomhole pressure (BHP). Initially a blanket sand bounded by zones of higher minimum in-situ stress is considered, with stresses symmetrical about both the pay-zone axis and the wellbore. An elliptical fracture perimeter is assumed. Fluid flows are one-dimensional (1D) Newtonian in the direction of the pay zone. Two models, FL1 and FL2, are developed. In FL1, a discontinuous stress variation is approximated by a y2 variation in the vertical coordinate, and the fracture criterion, Ki = Kc, is satisfied at both major and minor axes. The net pressure at the tip, Lf, of the long axis required by the boundary condition Ki = Kc does not seem crucial in determining fracture height or BHP (compare with one group of published models that assumes p = 0 at Lf). Model FL2 properly represents the discontinuous stresses, and satisfies Ki = Kc at the wellbore but not at the tip of the long axis. A parametric study is made, with both models, of the comparative effects of stress contrast, Kc, pay-zone height, h, and Young's modulus, E, on fracture height and BHP. Results indicate that Kc does not have as much effect as either E or, at least for large stress contrasts. Model FL2 suggests the possibility of a rapid growth in fracture height as is reduced. Such modeling may be able to give an upper or "safe" limit on the pumping parameters ( and ) to ensure good containment. When the stress contrast is high, 700 psi [4826 kPa], an analytic derivation of BHP appears to be a good approximation for the parameters we use, if everywhere the fracture height is assumed equal to the pay zone height. Although leakoff is neglected here, subsequent modeling results show that, for leak off coefficients 0.001 ft- min [3.9 × 10 -5 m.s ], the results herein are a good approximation to the case when leak off is included. Introduction In their essence, models of hydraulic fracture propagation involve elasticity theory and fluid mechanics. The first is concerned with the fracture opening or width, w(p), as a function of net pressure on the fracture faces, while the second is concerned with the pressure drop, p(w), caused by the flow of viscous fluids in the fracture. Simultaneous solution of these equations includes a boundary condition that often takes the form Ki = Kc, where Ki is the stress-intensity factor at a point on the fracture tip, and Kc is the fracture toughness. The final solution is very complex in 3D, when a vertical fracture can expand vertically as well as horizontally along the pay zone. Thus, the first solutions were essentially two-dimensional (2D), and they assumed that the fracture height, hf, was fixed at the pay zone height, h. The 2D solutions were clustered in two groups as summarized by Nordgren, Perkins, and Geertsma and Haafkens. The first grouping, based on a model by Christianovich and Zheltov, assumed that the sides of an elongated, vertical fracture were parallel (i.e., free slippage between the pay and bounding zones, or no vertical stiffness). Other papers in this grouping included Geertsma and de Klerk, Daneshy and Settari. SPEJ P. 870^

Vertical Growth of Hydraulic Fractures in Layered Formations

2021 ◽  
Author(s):  
Vibhas J. Pandey ◽  
Vamegh Rasouli
Keyword(s):  
Pressure Distribution ◽  
Solid Mechanics ◽  
High Rate ◽  
Design Parameters ◽  
Hydraulic Fractures ◽  
Vertical Wells ◽  
Wide Range ◽  
Net Pressure ◽  
Fracture Height ◽  
Injection Rates

AbstractFracture growth in layered formations with depth-dependent properties has been a topic of interest amongst researchers because of its critical influence on well performance. This paper revisits some of the existing height-growth models and discusses the evaluation process of a new and modified model developed after incorporating additional constraints.The net-pressure is the primary driver behind fracture propagation and the pressure distribution in the fracture plays an important role in vertical propagation, as it supplies the necessary energy for fracture advancement in the presence of opposing forces. The workflow adopted for this study included developing a preliminary model that solves a system of non-linear equations iteratively to arrive at fracture height versus net pressure mapping. The theoretical results were then compared to those available in the literature. The solution set was then extended to a 100-layer model after incorporating additional constraints using superposition techniques.The predicted outcomes were finally compared to the fracture height observations made in the field on several treatments.A reasonable agreement between model-predicted and observed height was observed when a comparison between the two was made, for most cases.The majority of these treatments were pumped in vertical wells, at low injection rates of up to 8.0 bbl/min (0.021 m3/s) where net pressures were intentionally restricted to 250 psi (1.72 MPa) in order to prevent fracture rotation to the horizontal plane.The leak-off was minimal given the low permeability formations. In some cases, however, the pumping parameters and fluid imparted pressure distribution appeared to dominate. Overall, it was apparent that for a slowly advancing fracture front, which is the case in low injection rate treatments, the fracture height could be predicted with reasonable accuracy. This condition could also be met in high rate treatments pumped down multiple perforation clusters such as in horizontal wells, though fracture-height measurement may not be as straightforward as in vertical wells.The model developed under the current study is suitable for vertical wells where fracture treatments are pumped at low injection rates. The solid-mechanics solution that is presented here is independent of pumping parameters and can be readily implemented to assist in selection of critical design parameters prior to the job, with a wide range of applicability worldwide.

Numerical Simulation Study of Proppant Transport in Cross Fractures

2022 ◽  
Author(s):  
Cong Lu ◽  
Li Ma ◽  
Jianchun Guo
Keyword(s):  
Hydraulic Fracturing ◽  
Transport Model ◽  
Injection Rate ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Fluid Viscosity ◽  
Natural Fractures ◽  
Fracturing Fluid ◽  
Proppant Transport ◽  
Approach Angle

Abstract Hydraulic fracturing technology is an important means to stimulate unconventional reservoirs, and the placement morphology of proppant in cross fractures is a key factor affecting the effect of hydraulic fracturing. It is very important to study the proppant transport law in cross fractures. In order to study the proppant transportation law in cross fractures, based on the CFD-DEM method, a proppant transport model in cross fractures was established. From the two aspects of the flow field in the fractures and the morphology of the proppant dune, the influence of the natural fracture approach angle, the fracturing fluid viscosity and injection rate on the proppant transport is studied. Based on the principle of hydropower similarity, the conductivity of proppant dune under different conditions is quantitatively studied. The results show that the natural fracture approach angle affects the distribution of proppant and fracturing fluid in natural fractures, and further affects the proppant placement morphology in hydraulic fractures and natural fractures. When the fracturing fluid viscosity is low and the displacement is small, the proppant forms a "high and narrow" dune at the entrance of the fracture. With the increase of the fracturing fluid viscosity and injection rate, the proppant settles to form a "short and wide" placement morphology. Compared with the natural fracture approach angle, the fracturing fluid viscosity and injection rate have a more significant impact on the conductivity of proppant dune. This paper investigated the proppant transportation in cross fractures, and quantitatively analyzes the conductivity of proppant dunes with different placement morphology. The results of this study can provide theoretical guidance for the design of hydraulic fracturing.

Hydraulic Fracture Treatment and Landing Zone Interval Optimization: An Eagle Ford Case Study

2022 ◽  
Author(s):  
Abdulrahim K. Al Mulhim ◽  
Jennifer L. Miskimins ◽  
Ali Tura
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Three Dimensional ◽  
Fracture Treatment ◽  
Fracturing Fluid ◽  
Eagle Ford ◽  
Landing Zone ◽  
Fracturing Fluids ◽  
Austin Chalk ◽  
The Subject

Abstract This paper focuses on optimizing future well landing zones and their corresponding hydraulic fracture treatments in the Eagle Ford shale play. The optimum landing zone and stimulation treatment were determined by analyzing multiple landing zone options, including the lower Austin Chalk, Eagle Ford, and Pepper Shale, with several hydraulic fracturing treatment possibilities. Fracturing fluids and their volume, proppant size, and cluster spacing were investigated to determine the optimum hydraulic fracturing treatment for the subject geologic area. Ranges of 75,000 to 300,000 gallons of pure gel, pure slickwater, and hybrid fracturing fluids along with 20/40, 30/50, 40/70, and 100 mesh proppant were tested. Cluster spacing of twenty feet to eighty feet were also sensitized in this study. A fully three-dimensional hydraulic fracture modeling software was used to develop a geological and geomechanical model of the studied area. The generated model was calibrated with available field data to ensure that the model reflects the area's geological and geomechanical characteristics. The developed model was used to create fracture results for each sensitized parameter. Production analysis was performed for all fracture models to determine the optimum landing zone and fracturing treatment implications. The study shows that the Eagle Ford had better production than the lower Austin Chalk in the subject area. The Pepper Shale had the highest potential hydrocarbon production, around 326 Mbbl cumulative, when fractured with a pure gel treatment. The analyses showed that a hybrid treatment with 70% gel and 30% slickwater yielded the optimum production due to the treatment economics even though the highest production was obtained using the pure gel. Treating the formation with larger proppant provided better production than smaller proppant due to conductivity concerns associated with damaging mechanisms in the studied area. Since increasing the volume above 175,000 gallons caused a negligible increase in the production, 175,000 gallons of fracturing fluid per stage appeared to be the optimum fracturing fluid volume. Thirty-foot cluster spacing was the optimum spacing in the study area. Overall, the study suggests that oil production can be improved in the Eagle Ford study area through a detailed workflow development and optimization process. The hydraulic fracture treatment and landing zone optimization workflow ensures optimum hydrocarbon extraction from the study area. The developed workflow can be applied to new unconventional plays instead of using trial and error methods.

Recycling Fracturing Flowback Water for Use in Hydraulic Fracturing: Influence of Organic Matter on Stability of Carboxyl-Methyl-Cellulose-Based Fracturing Fluids

SPE Journal ◽  
2016 ◽  
Vol 21 (04) ◽  
pp. 1358-1369 ◽  
Author(s):  
N.. Esmaeilirad ◽  
C.. Terry ◽  
Herron Kennedy ◽  
A.. Prior ◽  
K.. Carlson
Keyword(s):  
Organic Matter ◽  
Hydraulic Fracturing ◽  
Experimental Studies ◽  
Methyl Cellulose ◽  
Organic Content ◽  
Fluid Viscosity ◽  
Fracturing Fluid ◽  
Chain Polymer ◽  
Fracturing Fluids ◽  
Model Water

Summary Recycling oilfield wastewater for hydraulic fracturing requires a good understanding of the water chemical characteristics and how these interact with the fracturing fluid. The viscosity and rheological properties of fracturing fluids affect proppant placement, length and width of fractures, fracture conductivity, and, consequently, the success of the treatment. The objective of the research described here was to understand if dissolved organic matter (DOM) at high concentrations influences subsequent fracturing with a gelled fluid. Experimental studies were conducted on four types of water: (1) model water with low DOM, (2) recycled water from an industrial-treatment facility (medium DOM), (3) untreated early-time flowback (ETFB) water (high DOM), and (4) untreated produced water (high DOM). A low-pH, zirconium-crosslinker-gelled fluid at 200°F was examined in the study. All three water samples that had significant levels of organic matter [total organic content (TOC) > 1000 mg/L] exhibited lower peak viscosities and more-rapid viscosity decay than the model water without organic matter. The destabilizing influence of organic matter on carboxyl methyl cellulose (CMC) gelled fracturing-fluid viscosity is thought to be caused by secondary crosslinking of the short-chain polymer residuals in the flowback, resulting in lower initial viscosity and stability.

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