scholarly journals Apparent Toughness Anisotropy Induced by Roughness of in Situ Stress: A Mechanism that Hinders Vertical Growth of Hydraulic Fractures and Its Simplified Modeling

2019 ◽  
Author(s):  
Pengcheng Fu ◽  
Jixiang Huang ◽  
Randolph R. Settgast ◽  
Joseph P. Morris ◽  
Frederick J. Ryerson
Keyword(s):  
In Situ Stress ◽  
Hydraulic Fractures ◽  
Vertical Growth ◽  
Simplified Modeling

scholarly journals Apparent Toughness Anisotropy Induced by “Roughness” of In-Situ Stress: A Mechanism That Hinders Vertical Growth of Hydraulic Fractures and Its Simplified Modeling

SPE Journal ◽  
2019 ◽  
Vol 24 (05) ◽  
pp. 2148-2162 ◽  
Author(s):  
Pengcheng Fu ◽  
Jixiang Huang ◽  
Randolph R. Settgast ◽  
Joseph P. Morris ◽  
Frederick J. Ryerson
Keyword(s):  
Hydraulic Fracture ◽  
High Stress ◽  
In Situ Stress ◽  
Height Growth ◽  
Hydraulic Fractures ◽  
Simple Relationship ◽  
Vertical Growth ◽  
Stress Profiles ◽  
Fracture Height

Summary The height growth of a hydraulic fracture is known to be affected by many factors that are related to the layered structure of sedimentary rocks. Although these factors are often used to qualitatively explain why hydraulic fractures usually have well–bounded height growth, most of them cannot be directly and quantitatively characterized for a given reservoir to enable a priori prediction of fracture–height growth. In this work, we study the role of the “roughness” of in–situ–stress profiles, in particular alternating low and high stress among rock layers, in determining the tendency of a hydraulic fracture to propagate horizontally vs. vertically. We found that a hydraulic fracture propagates horizontally in low–stress layers ahead of neighboring high–stress layers. Under such a configuration, a fracture–mechanics principle dictates that the net pressure required for horizontal growth of high–stress layers within the current fracture height is significantly lower than that required for additional vertical growth across rock layers. Without explicit consideration of the stress–roughness profile, the system behaves as if the rock is tougher against vertical propagation than it is against horizontal fracture propagation. We developed a simple relationship between the apparent differential rock toughness and characteristics of the stress roughness that induce equivalent overall fracture shapes. This relationship enables existing hydraulic–fracture models to represent the effects of rough in–situ stress on fracture growth without directly representing the fine–resolution rough–stress profiles.

Roughness of Hydraulic Fractures: Importance of In-Situ Stress and Tip Processes

SPE Journal ◽  
2001 ◽  
Vol 6 (01) ◽  
pp. 4-13 ◽  
Author(s):  
D.B. van Dam ◽  
C.J. de Pater
Keyword(s):  
In Situ Stress ◽  
Hydraulic Fractures

scholarly journals Numerical Investigation of Injection-Induced Fracture Propagation in Brittle Rocks with Two Injection Wells by a Modified Fluid-Mechanical Coupling Model

Energies ◽  
2020 ◽  
Vol 13 (18) ◽  
pp. 4718
Author(s):  
Song Wang ◽  
Jian Zhou ◽  
Luqing Zhang ◽  
Zhenhua Han
Keyword(s):  
Fracture Propagation ◽  
In Situ Stress ◽  
Hydraulic Fractures ◽  
Fracture Networks ◽  
Breakdown Pressure ◽  
Injection Wells ◽  
Mechanical Coupling ◽  
Stress Shadow ◽  
Well Spacing

Hydraulic fracturing is a key technical means for stimulating tight and low permeability reservoirs to improve the production, which is widely employed in the development of unconventional energy resources, including shale gas, shale oil, gas hydrate, and dry hot rock. Although significant progress has been made in the simulation of fracturing a single well using two-dimensional Particle Flow Code (PFC2D), the understanding of the multi-well hydraulic fracturing characteristics is still limited. Exploring the mechanisms of fluid-driven fracture initiation, propagation and interaction under multi-well fracturing conditions is of great theoretical significance for creating complex fracture networks in the reservoir. In this study, a series of two-well fracturing simulations by a modified fluid-mechanical coupling algorithm were conducted to systematically investigate the effects of injection sequence and well spacing on breakdown pressure, fracture propagation and stress shadow. The results show that both injection sequence and well spacing make little difference on breakdown pressure but have huge impacts on fracture propagation pressure. Especially under hydrostatic pressure conditions, simultaneous injection and small well spacing increase the pore pressure between two injection wells and reduce the effective stress of rock to achieve lower fracture propagation pressure. The injection sequence can change the propagation direction of hydraulic fractures. When the in-situ stress is hydrostatic pressure, simultaneous injection compels the fractures to deflect and tend to propagate horizontally, which promotes the formation of complex fracture networks between two injection wells. When the maximum in-situ stress is in the horizontal direction, asynchronous injection is more conducive to the parallel propagation of multiple hydraulic fractures. Nevertheless, excessively small or large well spacing reduces the number of fracture branches in fracture networks. In addition, the stress shadow effect is found to be sensitive to both injection sequence and well spacing.

The Cross-Sectional Shapes of Longitudinal Hydraulic Fractures

1984 ◽  
Vol 106 (4) ◽  
pp. 554-561 ◽  
Author(s):  
D. Segalman
Keyword(s):  
Mathematical Formulation ◽  
High Stress ◽  
In Situ Stress ◽  
Hydraulic Fractures ◽  
Stress Distributions ◽  
Type Problem ◽  
Cross Sectional ◽  
The Cross ◽  
Sectional Shape

A mathematical formulation has been developed for calculating the cross-sectional shape of hydraulic fractures. This formulation treats the problem as a free-boundary-type problem and is modeled after mathematical formulations developed for contact and lubrication problems. Numerical solution of the resulting equations has been used to address problems involving particularly difficult in-situ stress distributions, including problems in which the fracture breaks through high-stress barriers. The technique is illustrated on two example problems.

Micromechanical Model for Simulating Hydraulic Fractures of Rock

2005 ◽  
Vol 9 ◽  
pp. 127-136 ◽  
Author(s):  
Tian Hong Yang ◽  
Leslie George Tham ◽  
S.Y. Wang ◽  
Wan Cheng Zhu ◽  
Lian Chong Li ◽  
...  
Keyword(s):  
Numerical Model ◽  
Stress Ratio ◽  
Failure Process ◽  
Micromechanical Model ◽  
In Situ Stress ◽  
Hydraulic Fractures ◽  
Breakdown Pressure ◽  
Heterogeneous Rocks ◽  
Material Homogeneity

A numerical model is developed to study hydraulic fracturing in permeable and heterogeneous rocks, coupling with the flow and failure process. The effects of flow and in-situ stress ratio on fracture, material homogeneity and breakdown pressure are specifically studied.

Pressure Interpretations in Acid Fracturing Treatments

2021 ◽  
Author(s):  
Vibhas J. Pandey
Keyword(s):  
In Situ Stress ◽  
Hydraulic Fractures ◽  
Fluid Viscosity ◽  
Acid Rock ◽  
Rock Interaction ◽  
Fracture Width ◽  
Acid Fracturing ◽  
In Situ Conditions ◽  
Net Pressure

Abstract Acid fracturing is a preferred method of stimulating low permeability limestone formations throughout the world. The treatment consists of pumping alternating cycles of viscous pad and acid to promote differential etching, thereby creating a conductive acid-etched fracture. Acid-type, pad and acid volumes, and the injection rates in the designed pump schedule are based on treatment objectives, rock-types and in-situ conditions such as temperatures, in-situ stress, proximity to water-bearing layers, and others. During the acid fracturing treatment, the acid-rock interaction is often marked by signature pressure responses, that are a combined outcome of acid reaction kinetics, responses to changes in fluid viscosity and densities, fluid-frictional drop in narrow hydraulic fractures, and other such parameters. This paper focuses on interpretation of bottomhole pressures during acid fracturing treatment to separate these individual effects and determine the effectiveness of the treatment. Unlike propped fracturing treatments where most fracturing treatments result in net pressure gain, acid fracturing treatments seldom result in net pressure increase at the end of the treatment because the in-situ stresses are generally relieved during the rock-dissolution and fracture width creation process that results from acid-mineral reactions. Not only is the extent of stress relief evident from the difference in the start and the end of the treatment instantaneous shut-in pressures, the loss of stresses is also apparent during the treatment itself, especially in jobs where the treatment data is constantly monitored and evaluated in real-time. The study reveals that the changes in pressure responses with the onset of acid in the formation can be successfully used to determine the effectiveness of treatment design and can aid in carrying out informed changes during the treatment. Better understanding of these responses can also lead to more effective treatment designs for future jobs. The interpretation developed in the study can be applied to most of the acid fracturing treatments that are pumped worldwide.

The effect of kerogen on the elastic anisotropy of organic-rich shales

Geophysics ◽  
2013 ◽  
Vol 78 (2) ◽  
pp. D65-D74 ◽  
Author(s):  
Colin M. Sayers
Keyword(s):  
Elastic Properties ◽  
Trajectory Optimization ◽  
Elastic Anisotropy ◽  
In Situ Stress ◽  
Hydraulic Fractures ◽  
Deformation And Failure ◽  
Reservoir Rocks ◽  
Stress Changes ◽  
Shale Anisotropy

The elastic properties of reservoir rocks are important for geomechanics applications; the most important of which are: analysis of stress changes due to production, analysis of rock deformation and failure, wellbore trajectory optimization, and the design of hydraulic fractures. Organic-rich shales are often observed to be strongly anisotropic due to the partial alignment of anisotropic clay minerals and the bedding-parallel lamination of organic material within the shale. Neglecting shale anisotropy may lead to incorrect estimates of the in situ stress or stress changes resulting from production. As a result, isotropic models may fail to describe geomechanical behavior correctly. The distribution of the organic phase plays an important role in determining the elastic properties of organic-rich shales, and this has a significant effect on production-induced stress changes. The presence of kerogen leads to a decrease in all of the elastic moduli, and has a significant effect on the geomechanical behavior of shales. The change in horizontal effective stress for a given change in pore pressure resulting from production is greater for kerogen-rich shales, and the neglect of anisotropy in predicting such stress changes may lead to significant errors.

Containment of Massive Hydraulic Fractures

1978 ◽  
Vol 18 (01) ◽  
pp. 27-32 ◽  
Author(s):  
E.R. Simonson ◽  
A.S. Abou-Sayed ◽  
R.J. Clifton
Keyword(s):  
Hydraulic Fracture ◽  
Oil And Gas ◽  
Fracture Propagation ◽  
Rocky Mountain ◽  
In Situ Stress ◽  
Hydraulic Fractures ◽  
Pressure Gradients ◽  
In Situ Stresses ◽  
Gas Bearing

Abstract Hydraulic fracture containment is discussed in relationship to linear elastic fracture mechanics. Three cases are analyzed,the effect of different material properties for the pay zone and the barrier formation,the characteristics of fracture propagation into regions of varying in-situ stress, propagation into regions of varying in-situ stress, andthe effect of hydrostatic pressure gradients on fracture propagation into overlying or underlying barrier formations. Analysis shows the importance of the elastic properties, the in-situ stresses, and the pressure gradients on fracture containment. Introduction Application of massive hydraulic fracture (MHF) techniques to the Rocky Mountain gas fields has been uneven, with some successes and some failures. The primary thrust of rock mechanics research in this area is to understand those factors that contribute to the success of MHF techniques and those conditions that lead to failures. There are many possible reasons why MHF techniques fail, including migration of the fracture into overlying or underlying barrier formations, degradation of permeability caused by application of hydraulic permeability caused by application of hydraulic fracturing fluid, loss of fracturing fluid into preexisting cracks or fissures, or extreme errors in preexisting cracks or fissures, or extreme errors in estimating the quantity of in-place gas. Also, a poor estimate of the in-situ permeability can result in failures that may "appear" to be caused by the hydraulic fracture process. Previous research showed that in-situ permeabilities can be one order of magnitude or more lower than permeabilities measured at near atmospheric conditions. Moreover, studies have investigated the degradation in both fracture permeability and formation permeability caused by the application of hydraulic fracture fluids. Further discussion of this subject is beyond the scope of this paper. This study will deal mainly with the containment of hydraulic fractures to the pay zone. In general, the lithology of the Rocky Mountain region is composed of oil- and gas-bearing sandstone layers interspaced with shales (Fig. 1). However, some sandstone layers may be water aquifers and penetration of the hydraulic fracture into these penetration of the hydraulic fracture into these aquifer layers is undesirable. Also, the shale layers can separate producible oil- and gas-bearing zones from nonproducible ones. Shale layers between the pay zone and other zones can be vital in increasing successful stimulation. If the shale layers act as barrier layers, the hydraulic fracture can be contained within the pay zone. The in-situ stresses and the stiffness, as characterized by the shear modulus of the zones, play significant roles in the containment of a play significant roles in the containment of a hydraulic fracture. The in-situ stresses result from forces in the earth's crust and constitute the compressive far-field stresses that act to close the hydraulic fracture. Fig. 2 shows a schematic representation of in-situ stresses acting on a vertical hydraulic fracture. Horizontal components of in-situ stresses may vary from layer to layer (Fig. 2). For example, direct measurements of in-situ stresses in shales has shown the minimum horizontal principal stress is nearly equal to the overburden principal stress is nearly equal to the overburden stress. SPEJ P. 27

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