Power spectrum of hydraulic fractures with constricted opening

2021 ◽  
Author(s):  
Arcady Dyskin ◽  
Elena Pasternak
Keyword(s):  
Power Spectrum ◽  
Hydraulic Fracture ◽  
Amplitude Ratio ◽  
Normal Component ◽  
Hydraulic Fractures ◽  
Fracturing Fluid ◽  
Impact Oscillator ◽  
Fracture Opening ◽  
Two Peaks

<p>Propagation of hydraulic fractures in rocks is often a non-smooth process, which leaves behind a number of rock bridges distributed all over the fracture. The bridges constrict the fracture opening and thus affect the determination of hydraulic fracture dimensions from the volume of pump-in fracturing fluid. This makes it necessary to detect the emergence of bridges and their concentration over the fracture surface.</p><p>Opening of hydraulic fractures in rocks is determined by a balance of pressure from the fracturing fluid and the normal component of the in-situ compressive stress. If an external excitation is applied (e.g. by a seismic wave), closure of the fracture is additionally resisted by the stiffness of fracturing fluid. Subsequently, a simple model of hydraulic fracture is presented by a bilinear spring with a certain stiffness in tension and a very high stiffness in compression. This constitutes so-called bilinear oscillator [1, 2] in which the compressive stiffness considerably exceeds the tensile one. The presence of bridges increases stiffness in tension thus reducing bilinearity of the modelling spring. Therefore the determination of the bilinearity is a first step in the reconstructing the effective stiffness of the bridges.  </p><p>We use the model of bilinear oscillator, identify multiple resonances and determine the first two harmonics (or first two peaks of in the power spectrum). The ratio of their amplitudes directly depends upon the bilinearity (ratio of compressive to tensile stiffnesses), hence the bilinearity is determinable from the amplitude ratio. Then the effective bridge stiffness can be estimated.</p><p>1. Dyskin, A.V., E. Pasternak and E. Pelinovsky, 2012. Periodic motions and resonances of impact oscillators. Journal of Sound and Vibration 331(12) 2856-2873. ISBN/ISSN 0022-460X, 04/06/2012.</p><p>2. Pasternak, E., A. Dyskin<sup></sup>and Ch. Qi, 2020. Impact oscillator with non-zero bouncing point. International Journal of Engineering Science, 103203.</p><p><strong>Acknowledgement</strong>. The authors acknowledge support from the Australian Research Council through project DP190103260.</p>

Controlling the Height of Multiple Hydraulic Fractures in Layered Media

SPE Journal ◽  
2016 ◽  
Vol 21 (01) ◽  
pp. 256-263 ◽  
Author(s):  
Aditya Khanna ◽  
Andrei Kotousov
Keyword(s):  
Fluid Pressure ◽  
Pressure Control ◽  
Shielding Effect ◽  
Hydraulic Fractures ◽  
Fracturing Fluid ◽  
Fracture Spacing ◽  
Gas Recovery ◽  
Fracture Opening ◽  
Fracture Height ◽  
Fracture Height Containment

Summary Fracture-height containment is desirable in hydraulic-fracturing treatments because it can result in better efficiency of oil or gas recovery and have less impact on the environment. Several mechanisms of the containment of a single hydraulic fracture were investigated in the past, and the outcomes of these studies are now well-documented in the open literature. However, the effectiveness of these mechanisms in the case of multiple closely spaced hydraulic fractures has not received much attention. The latter situation typically arises in the case of multiple transverse fractures emanating from a single horizontal wellbore. In this paper, we develop a mathematical model that one can use to assess the fracture-interaction phenomenon as well as the effect of the modulus contrast between adjacent rock layers. We consider the situation in which one must contain the hydraulic fractures entirely in the pay zone and investigate fracturing-fluid-pressure control as a possible mechanism of height containment. It is demonstrated that when the fracture spacing becomes comparable with the fracture height, the interaction between the fractures produces a shielding effect. In this case, the fracturing-fluid pressure that ensures fracture containment is greater in comparison with the case of a single isolated fracture. However, the fracture opening is also smaller in the case of closely spaced fractures. The dependence of the fracturing-fluid pressure and fracture opening on the fracture spacing needs to be taken into consideration during the selection of fracture spacing for a particular treatment.

scholarly journals Fault Triggering Mechanisms for Hydraulic Fracturing-Induced Seismicity From the Preston New Road, UK Case Study

2021 ◽  
Vol 9 ◽  
Author(s):  
Tom Kettlety ◽  
James P. Verdon
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Induced Seismicity ◽  
Elastic Stress ◽  
Fluid Pressure ◽  
Stress Transfer ◽  
Fault Reactivation ◽  
Hydraulic Fractures ◽  
Fracture Opening ◽  
Triggering Mechanisms

We investigate the physical mechanisms governing the activation of faults during hydraulic fracturing. Recent studies have debated the varying importance of different fault reactivation mechanisms in different settings. Pore pressure increase caused by injection is generally considered to be the primary driver of induced seismicity. However, in very tight reservoir rocks, unless a fracture network exists to act as a hydraulic conduit, the rate of diffusion may be too low to explain the spatio-temporal evolution of some microseismic sequences. Thus, elastic and poroelastic stress transfer and aseismic slip have been invoked to explain observations of events occurring beyond the expected distance of a reasonable diffusive front. In this study we use the high quality microseismic data acquired during hydraulic fracturing at the Preston New Road (PNR) wells, Lancashire, UK, to examine fault triggering mechanisms. Injection through both wells generated felt induced seismicity—an ML 1.6 during PNR-1z injection in 2018 and an ML 2.9 during PNR-2 in 2019—and the microseismic observations show that each operation activated different faults with different orientations. Previous studies have already shown that PNR-1z seismicity was triggered by a combination of both direct hydraulic effects and elastic stress transfer generated by hydraulic fracture opening. Here we perform a similar analysis of the PNR-2 seismicity, finding that the PNR-2 fault triggering was mostly likely dominated by the diffusion of increased fluid pressure through a secondary zone of hydraulic fractures. However, elastic stress transfer caused by hydraulic fracture opening would have also acted to promote slip. It is significant that no microseismicity was observed on the previously activated fault during PNR-2 operations. This dataset therefore provides a unique opportunity to estimate the minimum perturbation required to activate the fault. As it appears that there was no hydraulic connection between them during each stimulation, any perturbation caused to the PNR-1z fault by PNR-2 stimulation must be through elastic or poroelastic stress transfer. As such, by computing the stress transfer created by PNR-2 stimulation onto the PNR-1z fault, we are able to approximate the minimum bound for the required stress perturbation: in excess of 0.1 MPa, orders of magnitude larger than stated estimates of a generalized triggering threshold.

High Accuracy Estimation of Hydraulic Fracture Geometry Using Crosswell Electromagnetics

2021 ◽  
Author(s):  
Shubham Mishra ◽  
Vinil Reddy
Keyword(s):  
Hydraulic Fracture ◽  
Horizontal Wells ◽  
Hydraulic Fractures ◽  
Calibration Data ◽  
Formation Water ◽  
Fracturing Fluid ◽  
Production Forecast ◽  
Fracture Geometry ◽  
Field Development ◽  
Well Completion

Abstract Unconventional resources, which are typically characterized by poor porosity and permeability are being economically developed only after the introduction of hydraulic fracturing (HF) technology, which is required to stimulate the hydrocarbon flow from these impermeable/tight reservoir rocks. Since 1960, HF has been extensively used in the industry. HF is the process of (1) injecting viscous gel fluids through the wellbore into the subterranean hydrocarbon formation, at high pressures sufficient enough to exceed tensile strength of the rock and hydraulically induce cracks/fractures (2) followed by injecting proppant-laden fluid into the open fractures and packing up the fracture with proppant pack, after the injected fluid leaks off into formation. The resultant proppant pack keeps the induced fracture propped open and thus creates a highly conductive flow path for the hydrocarbon to flow from the far-field subterranean formation into the wellbore. Most the modern wells in unconventional reservoirs are horizontal/near-horizontal wells that are completed with large multiple HF treatments across the entire length of the horizontal wellbore (lateral), to increase the reservoir contact per well. Productivity of these wells is dictated by the stimulated reservoir volume (SRV), which is dependent on the number of fractures and conductive hydraulic fracture surface area of each fracture that is propped open. Therefore, estimation of the hydraulic fracture geometry (HFG) dimensions has become very critical for any unconventional field development. Key dimensions are hydraulic fracture length, height, and orientation, which are required to assess the optimum configuration of fracturing, well completion, and reservoir management strategy to achieve maximum production. Designs can be assessed based on HFG observations, and infill well trajectories, spacing, etc. can be planned for further field development. This workflow proposes a method to estimate and model all or at least two parameters of HFG in predominantly horizontal or nearly horizontal wells by use of interwell electromagnetic recordings. The foundation of this workflow is the difference in salinity, or more precisely resistivity, of the fracturing fluid and the resident fluid (hydrocarbon or formation water). The fracturing fluid is usually significantly less resistive than the hydrocarbon that is the dominant resident fluid where fracturing is usually conducted, or less resistive than the formation water in case the HF occurs in high water saturation regions. Therefore, the resistivity contrast between the two fluids will demarcate the boundary of hydraulic fractures and thus help in precisely modeling some or all parameters of HFG. The interwell recordings can be interpreted along a 2D plane between the two wells, one of them bearing the transmitter and the other with the receiver. The interpretations along a 2D plane can be used to calibrate a 3D unstructured HF model, thereby introducing a reliable calibration input that did not exist before. There can be multiple such 2D planes as more than one well can have a receiver, and, in that case, the 3D HF model has more calibration data and is even more precise. The reason this workflow significantly improves precision in HFG estimation and modeling is that it provides the ability to demarcate only the open portion of the HF and not the entire volume where pumping fluid entered, which would include parts that closed too quickly to contribute to the production from the well. Today, the industry, by its best methods, can only see the entire rock volume that broke due to fracturing, although significant parts of that broken volume might not be contributing to the production and thus are irrelevant in the 3D models upon which important decisions such as production forecast and project economics are based.

The effect of gravity on the shape and direction of vertical hydraulic fractures

2020 ◽  
Vol 60 (2) ◽  
pp. 668
Author(s):  
Saeed Salimzadeh
Keyword(s):  
Hydraulic Fracturing ◽  
Shale Gas ◽  
Hydraulic Fracture ◽  
Hydraulic Fractures ◽  
Fluid Viscosity ◽  
Gas Reservoirs ◽  
Unconventional Gas Reservoirs ◽  
Fracture Fluid ◽  
Fracture Opening

Australia has great potential for shale gas development that can reshape the future of energy in the country. Hydraulic fracturing has been proven as an efficient method to improve recovery from unconventional gas reservoirs. Shale gas hydraulic fracturing is a very complex, multi-physics process, and numerical modelling to design and predict the growth of hydraulic fractures is gaining a lot of interest around the world. The initiation and propagation direction of hydraulic fractures are controlled by in-situ rock stresses, local natural fractures and larger faults. In the propagation of vertical hydraulic fractures, the fracture footprint may extend tens to hundreds of metres, over which the in-situ stresses vary due to gravity and the weight of the rock layers. Proppants, which are added to the hydraulic fracturing fluid to retain the fracture opening after depressurisation, add additional complexity to the propagation mechanics. Proppant distribution can affect the hydraulic fracture propagation by altering the hydraulic fracture fluid viscosity and by blocking the hydraulic fracture fluid flow. In this study, the effect of gravitational forces on proppant distribution and fracture footprint in vertically oriented hydraulic fractures are investigated using a robust finite element code and the results are discussed.

scholarly journals The Impact of Oriented Perforations on Fracture Propagation and Complexity in Hydraulic Fracturing

Processes ◽  
2018 ◽  
Vol 6 (11) ◽  
pp. 213 ◽  
Author(s):  
Liyuan Liu ◽  
Lianchong Li ◽  
Derek Elsworth ◽  
Sheng Zhi ◽  
Yongjun Yu
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
Hydraulic Fractures ◽  
Fracturing Fluid ◽  
Stress Criterion ◽  
Damage And Fracture ◽  
Fracturing Process ◽  
Heterogeneous Rock ◽  
The Impact

To better understand the interaction between hydraulic fracture and oriented perforation, a fully coupled finite element method (FEM)-based hydraulic-geomechanical fracture model accommodating gas sorption and damage has been developed. Damage conforms to a maximum stress criterion in tension and to Mohr–Coulomb limits in shear with heterogeneity represented by a Weibull distribution. Fracturing fluid flow, rock deformation and damage, and fracture propagation are collectively represented to study the complexity of hydraulic fracture initiation with perforations present in the near-wellbore region. The model is rigorously validated against experimental observations replicating failure stresses and styles during uniaxial compression and then hydraulic fracturing. The influences of perforation angle, in situ stress state, initial pore pressure, and properties of the fracturing fluid are fully explored. The numerical results show good agreement with experimental observations and the main features of the hydraulic fracturing process in heterogeneous rock are successfully captured. A larger perforation azimuth (angle) from the direction of the maximum principal stress induces a relatively larger curvature of the fracture during hydraulic fracture reorientation. Hydraulic fractures do not always initiate at the oriented perforations and the fractures induced in hydraulic fracturing are not always even and regular. Hydraulic fractures would initiate both around the wellbore and the oriented perforations when the perforation angle is >75°. For the liquid-based hydraulic fracturing, the critical perforation angle increases from 70° to 80°, with an increase in liquid viscosity from 10−3 Pa·s to 1 Pa·s. While for the gas fracturing, the critical perforation angle remains 62° to 63°. This study is of great significance in further understanding the near-wellbore impacts on hydraulic fracture propagation and complexity.

Natural-Gas-Foam Fluid Reduces Water Needed for Fracture Stimulations

2021 ◽  
Vol 73 (06) ◽  
pp. 56-57
Author(s):  
Chris Carpenter
Keyword(s):  
Natural Gas ◽  
Hydraulic Fracture ◽  
Hydraulic Fractures ◽  
Geological Model ◽  
Flow Modeling ◽  
Reservoir Model ◽  
Fracturing Fluid ◽  
Fracturing Fluids ◽  
Rock Characterization

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201450, “Reducing the Volume of Water Needed For Hydraulic Fracturing by Using Natural-Gas-Foamed Stimulation Fluid,” by Raj Malpani, SPE, Chris Daeffler, and Sandeep Verma, SPE, Schlumberger, et al., prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, Colorado, 5–7 October. The paper has not been peer reviewed. Using natural-gas (NG) -foam fracturing fluids reduces the enormous water requirements for stimulation by as much as 60 to 80% and poses benefits for productivity in water-sensitive formations. The study outlined in the complete paper aims to characterize hydraulic-fracture geometry and quantify the expected production when using an NG-foam fracturing fluid. Using validated models, the authors provide a comparative analysis to determine the advantages of using NG foams relative to conventionally used slickwater, linear gel, and crosslinked fluid. NG-Foam Fluids Although foamed fluids were first used in the 1960s, the use of nitrogen (N2) and carbon dioxide (CO2) foams has not been widely practiced because of cost, complexity, and unproven production benefits. The use of NG-foam fracturing fluid is not widespread either, but this study attempts to identify specific regions and reservoirs where the use of these fluids may lead to economic and long-term production benefits. The authors write that using NG foams is likely to provide long-term sustainable benefits in areas where water procurement and disposal costs are high, where natural gas may be available from a central processing facility through pipelines, and where the reservoir is relatively shallow and contains clay-bearing minerals. This work is inspired by a program sponsored by the US Department of Energy to investigate NG as an alternative to N2 and CO2 in foamed fracturing fluids. Initially, the project focused on identifying a thermodynamic path-way to use NG obtained from producing wells and processing plants. The study later extended into laboratory-scale experiments to measure NG-foam-fluid rheology, which was found to be comparable to foams based on N2 and CO2. The first step in the work flow is to build a static geological model to capture the reservoir description. The subsequent step is to use the rock characterization to simulate the induced hydraulic fractures. The hydraulic-fracture simulator also predicts the proppant distribution and its conductivity and treating pressure. The simulated treating pressure is matched with observed pressure during stimulation treatment to calibrate the hydraulic-fracture model. The hydraulic fractures are then gridded in the static geological model to generate the reservoir model for flow modeling. This is a critical step in the process because the static model is linked to the dynamic simulator without losing the details of the hydraulic fractures. The reservoir simulator is used to match the historical production performance to calibrate the reservoir model and forecast future production profiles. This hydraulic-fracture modeling, followed by the flow-modeling process, is repeated for various pumping schedules and recipes to perform a sensitivity analysis, which is detailed in the complete paper.

Hydraulic fracture oscillations in response to strong impulse

2020 ◽  
Author(s):  
Elena Pasternak ◽  
Arcady Dyskin
Keyword(s):  
Compressive Stress ◽  
Hydraulic Fracture ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Impact Oscillator ◽  
Impact Oscillators ◽  
Closed Fractures ◽  
The Impact ◽  
Very High

<p>Hydraulic fractures and the natural fractures in rock masses are closed by the in-situ compressive stress such that their opposite faces are in contact either with each other or with the proppant in hydraulic fractures or with gouge in the natural fractures. Subsequently, a pressure increase can produce negligible deformation in already closed fractures as compared to the deformation associated with the opening caused by sufficiently large tensile stress. This suggests a simple model of closed fracture as a bilinear spring with a certain stiffness in tension and a very high (potentially infinite) stiffness in compression. Therefore the oscillations of fractures can be reduced to the oscillations of a bilinear oscillator or impact oscillator [1] when the compressive stiffness considerably exceeds the tensile one. We use the simplest model of the impact oscillator with preload representing the action of the in-situ compressive stress. Based on this model, two sets of multiple resonances are identified and the reaction to impulsive load is determined. The harmonics of free oscillations are calculated. The knowledge of the first two harmonics is sufficient to recover the tensile stiffness and hence identify the geometric parameters of the fracture. The results of the research contribute to the development of the methods of fracture reconstruction and the hydraulic fracture monitoring.</p><ol><li>Dyskin, A.V., E. Pasternak and E. Pelinovsky, 2012. Periodic motions and resonances of impact oscillators. Journal of Sound and Vibration 331(12) 2856-2873. ISBN/ISSN 0022-460X, 04/06/2012.</li> </ol><p><strong>Acknowledgements</strong>. The authors acknowledge support from the Australian Research Council through project DP190103260. AVD acknowledges the support from the School of Civil and Transportation, Faculty of Engineering, Beijing University of Civil Engineering and Architecture.</p>

A new approach to the hydraulic fracture geometric dimensions determination

2017 ◽  
Vol 12 (1) ◽  
pp. 126-134
Author(s):  
A.M. Ilyasov
Keyword(s):  
Exact Solution ◽  
Hydraulic Fracture ◽  
Pressure Gauge ◽  
Hyperbolic Type ◽  
Fluid Injection ◽  
Fracturing Fluid ◽  
New Approach ◽  
Gauge Data ◽  
Bottomhole Pressure ◽  
Half Length

Based on the generalized Perkins-Kern-Nordgren model (PKN) for the development of a hyperbolic type vertical hydraulic fracture, an exact solution is obtained for the hydraulic fracture self-oscillations after terminating the fracturing fluid injection. These oscillations are excited by a rarefaction wave that occurs after the injection is stopped. The obtained solution was used to estimate the height, width and half-length of the hydraulic fracture at the time of stopping the hydraulic fracturing fluid injection based on the bottomhole pressure gauge data.

scholarly journals Numerical simulation of the laws of fracture propagation of multi-hole linear co-directional hydraulic fracturing

2021 ◽  
pp. 014459872198899
Author(s):  
Weiyong Lu ◽  
Changchun He
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Minimum Principle ◽  
Fracture Propagation ◽  
Axial Direction ◽  
Rock Breaking ◽  
Hydraulic Fractures ◽  
Directional Hydraulic Fracturing ◽  
Fracture Intersection ◽  
Expansion Stage

Directional rupture is one of the most important and most common problems related to rock breaking. The goal of directional rock breaking can be effectively achieved via multi-hole linear co-directional hydraulic fracturing. In this paper, the XSite software was utilized to verify the experimental results of multi-hole linear co-directional hydraulic fracturing., and its basic law is studied. The results indicate that the process of multi-hole linear co-directional hydraulic fracturing can be divided into four stages: water injection boost, hydraulic fracture initiation, and the unstable and stable propagation of hydraulic fracture. The stable expansion stage lasts longer and produces more microcracks than the unstable expansion stage. Due to the existence of the borehole-sealing device, the three-dimensional hydraulic fracture first initiates and expands along the axial direction in the bare borehole section, then extends along the axial direction in the non-bare hole section and finally expands along the axial direction in the rock mass without the borehole. The network formed by hydraulic fracture in rock is not a pure plane, but rather a curved spatial surface. The curved spatial surface passes through both the centre of the borehole and the axial direction relative to the borehole. Due to the boundary effect, the curved spatial surface goes toward the plane in which the maximum principal stress occurs. The local ground stress field is changed due to the initiation and propagation of hydraulic fractures. The propagation direction of the fractures between the fracturing boreholes will be deflected. A fracture propagation pressure that is greater than the minimum principle stress and a tension field that is induced in the leading edge of the fracture end, will aid to fracture intersection; as a result, the possibility of connecting the boreholes will increase.

scholarly journals Quantitative evaluation indexes of the spatial steering effect of directional perforation hydraulic fractures

2021 ◽  
pp. 014459872110102
Author(s):  
Lu Weiyong ◽  
He Changchun
Keyword(s):  
Quantitative Evaluation ◽  
Hydraulic Fracture ◽  
Deflection Angle ◽  
Hydraulic Fractures ◽  
Principal Stress Direction ◽  
Perforation Hole ◽  
Evaluation Indexes ◽  
Initiation Pressure ◽  
The Deflection Angle ◽  
Bending Fracture

To better evaluate the spatial steering effect of directional perforation hydraulic fractures, evaluation indexes for the spatial steering effect are first proposed in this paper. Then, these indexes are used to quantitatively evaluate existing physical experimental results. Finally, with the help of RFPA2D-Flow software, the influence of perforation length and azimuth on the spatial steering process of hydraulic fracture are quantitatively analysed using four evaluation indexes. It is shown by the results that the spatial deflection trajectory, deflection distance, deflection angle and initiation pressure of hydraulic fractures can be used as quantitative evaluation indexes for the spatial steering effect of hydraulic fractures. The deflection paths of directional perforation hydraulic fractures are basically the same. They all gradually deflect to the maximum horizontal principal stress direction from the perforation hole and finally represent a double-wing bending fracture. The deflection distance, deflection angle and initiation pressure of hydraulic fractures increase gradually with increasing perforation azimuth, and the sensitivity of the deflection angle to the perforation azimuth of hydraulic fractures also increases. With increasing perforation length, the deflection distance of hydraulic fractures increases gradually. However, the deflection angle and initiation pressure decrease gradually, as does the sensitivity.

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