On the Application of the Channel-Fracturing Technique to Soft Rock Formations

SPE Journal ◽  
2018 ◽  
Vol 24 (01) ◽  
pp. 395-412 ◽  
Author(s):  
Aditya Khanna ◽  
Andrei Kotousov ◽  
Hao Thanh Luong
Keyword(s):  
Parametric Study ◽  
Analytical Approach ◽  
Volume Fraction ◽  
Effective Conductivity ◽  
Soft Rock ◽  
Open Channels ◽  
Hydraulic Fractures ◽  
Fracture Conductivity ◽  
Rock Formations ◽  
Fracture Closure

Summary The application of the channel-fracturing technique can result in a significant increase in the conductivity of hydraulic fractures and reduced proppant usage. In soft rock formations, the conductivity of the partially propped fractures would depend not only on the volume fraction of the open channels, but also on the elastic deformation of open channels and fracture closure resulting from proppant consolidation and embedment. In this study, an analytical approach is developed for identifying the optimal proppant column spacing that maximizes the effective conductivity. The latter parameter can guide the design of the proppant-injection schedule and well-perforation scheme. To demonstrate the approach, we conduct a parametric study under realistic field conditions and identify the folds of increase in fracture conductivity and reduction in proppant use resulting from the optimized application of the channel-fracturing technique. The outcomes of the parametric study could be particularly useful in the application of the developed approach to soft rock formations.

High-Resolution and Multimaterial Fracture Productivity Calculator for the Successful Design of Channel Fracturing Jobs

2021 ◽  
Author(s):  
Dimitry Chuprakov ◽  
Ludmila Belyakova ◽  
Ivan Glaznev ◽  
Aleksandra Peshcherenko
Keyword(s):  
High Resolution ◽  
Effective Conductivity ◽  
Productivity Index ◽  
Hydraulic Fractures ◽  
Total Production ◽  
Fracture Conductivity ◽  
Hindered Settling ◽  
Accurate Evaluation ◽  
Skin Factor ◽  
Fracture Closure

Abstract We developed a high-resolution fracture productivity calculator to enable fast and accurate evaluation of hydraulic fractures modeled using a fine-scale 2D simulation of material placement. Using an example of channel fracturing treatments, we show how the productivity index, effective fracture conductivity, and skin factor are sensitive to variations in pumping schedule design and pulsing strategy. We perform fracturing simulations using an advanced high-resolution multiphysics model that includes coupled 2D hydrodynamics with geomechanics (pseudo-3D, or P3D, model), 2D transport of materials with tracking temperature exposure history, in-situ kinetics, and a hindered settling model, which includes the effect of fibers. For all simulated fracturing treatments, we accurately solve a problem of 3D planar fracture closure on heterogenous spatial distribution of solids, estimate 2D profiles of fracture width and stresses applied to proppants, and, as a result, obtain the complex and heterogenous shape of fracture conductivity with highly conductive cells owing to the presence of channels. Then, we also evaluate reservoir fluid inflows from a reservoir to fracture walls and further along a fracture to limited-size wellbore perforations. Solution of a productivity problem at the finest scale allows us to accurately evaluate key productivity characteristics: productivity index, dimensional and dimensionless effective conductivity, skin factor, and folds of increase, as well as the total production rate at any day and for any pressure drawdown in a well during well production life. We develop a workflow to understand how productivity of a fracture depends on variation of the pumping schedule and facilitate taking appropriate decisions about the best job design. The presented workflow gives insight into how new computationally efficient methods can enable fast, convenient, and accurate evaluation of the material placement design for maximum production with cost-saving channel fracturing technology.

Propagation, proppant transport and the evolution of transport properties of hydraulic fractures

2018 ◽  
Vol 855 ◽  
pp. 503-534 ◽  
Author(s):  
Jiehao Wang ◽  
Derek Elsworth ◽  
Martin K. Denison
Keyword(s):  
Preferential Flow ◽  
Fluid Pressure ◽  
Fracture Propagation ◽  
Hydraulic Fractures ◽  
Fracture Aperture ◽  
Fluid Viscosity ◽  
Fracture Conductivity ◽  
Proppant Transport ◽  
Fracture Closure ◽  
Proppant Embedment

Hydraulic fracturing is a widely used method for well stimulation to enhance hydrocarbon recovery. Permeability, or fluid conductivity, of the hydraulic fracture is a key parameter to determine the fluid production rate, and is principally conditioned by fracture geometry and the distribution of the encased proppant. A numerical model is developed to describe proppant transport within a propagating blade-shaped fracture towards defining the fracture conductivity and reservoir production after fracture closure. Fracture propagation is formulated based on the PKN-formalism coupled with advective transport of an equivalent slurry representing a proppant-laden fluid. Empirical constitutive relations are incorporated to define rheology of the slurry, proppant transport with bulk slurry flow, proppant gravitational settling, and finally the transition from Poiseuille (fracture) flow to Darcy (proppant pack) flow. At the maximum extent of the fluid-driven fracture, as driving pressure is released, a fracture closure model is employed to follow the evolution of fracture conductivity with the decreasing fluid pressure. This model is capable of accommodating the mechanical response of the proppant pack, fracture closure of potentially contacting rough surfaces, proppant embedment into fracture walls, and most importantly flexural displacement of the unsupported spans of the fracture. Results show that reduced fluid viscosity increases the length of the resulting fracture, while rapid leak-off decreases it, with both characteristics minimizing fracture width over converse conditions. Proppant density and size do not significantly influence fracture propagation. Proppant settling ensues throughout fracture advance, and is accelerated by a lower viscosity fluid or greater proppant density or size, resulting in accumulation of a proppant bed at the fracture base. ‘Screen-out’ of proppant at the fracture tip can occur where the fracture aperture is only several times the diameter of the individual proppant particles. After fracture closure, proppant packs comprising larger particles exhibit higher conductivity. More importantly, high-conductivity flow channels are necessarily formed around proppant banks due to the flexural displacement of the fracture walls, which offer preferential flow pathways and significantly influence the distribution of fluid transport. Higher compacting stresses are observed around the edge of proppant banks, resulting in greater depths of proppant embedment into the fracture walls and/or an increased potential for proppant crushing.

A Parametric Numerical Study of Radiative Transfer in Thermotropic Materials

2013 ◽  
Author(s):  
Adam C. Gladen ◽  
Susan C. Mantell ◽  
Jane H. Davidson
Keyword(s):  
Particle Size ◽  
Radiative Transfer ◽  
Optical Thickness ◽  
Parametric Study ◽  
Volume Fraction ◽  
Numerical Study ◽  
Anisotropic Scattering ◽  
Index Of Refraction ◽  
Spherical Particles ◽  
Size Parameter

A thermotropic material is modeled as an absorbing, thin slab containing anisotropic scattering, monodisperse, spherical particles. Monte Carlo ray tracing is used to solve the governing equation of radiative transfer. Predicted results are validated by comparison to the measured normal-hemispherical reflectance and transmittance of samples with various volume fraction and relative index of refraction. A parametric study elucidates the effects of particle size parameter, scattering albedo, and optical thickness on the normal-hemispherical transmittance, reflectance, and absorptance. The results are interpreted for a thermotropic material used for overheat protection of a polymer solar absorber. For the preferred particle size parameter of 2, the optical thickness should be less than 0.3 to ensure high transmittance in the clear state. To significantly reduce the transmittance and increase the reflectance in the translucent state, the optical thickness should be greater than 2.5 and the scattering albedo should be greater than 0.995. For optical thickness greater than 5, the reflectance is asymptotic and any further reduction in transmittance is through increased absorptance. A case study is used to illustrate how the parametric study can be used to guide the design of thermotropic materials. Low molecular weighted polyethylene in poly(methyl methacrylate) is identified as a potential thermotropic material. For this material and a particle radius of 200 nm, it is determined that the volume fraction and thickness should equal 10% and 1 mm, respectively.

scholarly journals OPTIMISATION OF HYDRAULIC FRACTURING DESIGN IN LOWER OLIGOCENE RESERVOIR, KINH NGU TRANG OILFIELD

2018 ◽  
Vol 18 (3) ◽  
pp. 323-337
Author(s):  
Nguyen Huu Truong
Keyword(s):  
Hydraulic Fracturing ◽  
Complex Structure ◽  
Power Requirement ◽  
Fracture Conductivity ◽  
Fracture Width ◽  
The North ◽  
Fracture Closure ◽  
Average Water ◽  
White Tiger ◽  
Fracture Height

Kinh Ngu Trang oilfield is of the block 09-2/09 offshore Vietnam, which is located in the Cuu Long basin, the distance from that field to Port of Vung Tau is around 140 km and it is about 14 km from the north of Rang Dong oilfield of the block 15.2, and around 50 km from the east of White Tiger in the block 09.1. That block accounts for total area of 992 km2 with the average water depth of around 50 m to 70 m. The characteristic of Oligocene E reservoir is tight oil in sandstone, very complicated with complex structure. Therefore, the big challenges in this reservoir are the low permeability and the low porosity of around 0.2 md to less than 1 md and 1% to less than 13%, respectively, leading to very low fracture conductivity among the fractures. Through the Minifrac test for reservoir with reservoir depth from 3,501 mMD to 3,525 mMD, the total leak-off coefficient and fracture closure pressure were determined as 0.005 ft/min0.5 and 9,100 psi, respectively. To create new fracture dimensions, hydraulic fracturing stimulation has been used to stimulate this reservoir, including proppant selection and fluid selection, pump power requirement. In this article, the authors present optimisation of hydraulic fracturing design using unified fracture design, the results show that optimum fracture dimensions include fracture half-length, fracture width and fracture height of 216 m, 0.34 inches and 31 m, respectively when using proppant mass of 150,000 lbs of 20/40 ISP Carbolite Ceramic proppant.

Pressure Depletion Mapping Using Multi-Well DFITs and its Applications in Hydraulic Fracture Characterization and Permeability Estimation: Examples from Montney Formation

2021 ◽  
Author(s):  
Behjat Haghshenas ◽  
Farhad Qanbari
Keyword(s):  
Data Analysis ◽  
Surface Area ◽  
Reservoir Simulation ◽  
Production Data ◽  
Hydraulic Fractures ◽  
Fracture Geometry ◽  
Fracture Conductivity ◽  
Field Case ◽  
Pressure Depletion ◽  
Montney Formation

Abstract Recovery factor for multi-fractured horizontal wells (MFHWs) at development spacing in tight reservoirs is closely related to the effective horizontal and vertical extents of the hydraulic fractures. Direct measurement of pressure depletion away from the existing producers can be used to estimate the extent of the hydraulic fractures. Monitoring wells equipped with downhole gauges, DFITs from multiple new wells close to an existing (parent) well, and calculation of formation pressure from drilling data are among the methods used for pressure depletion mapping. This study focuses on acquisition of pressure depletion data using multi-well diagnostic fracture injection tests (DFITs), analysis of the results using reservoir simulation, and integration of the results with production data analysis of the parent well using rate-transient analysis (RTA) and reservoir simulation. In this method, DFITs are run on all the new wells close to an existing (parent) well and the data is analyzed to estimate reservoir pressure at each DFIT location. A combination of the DFIT results provides a map of pressure depletion around the existing well, while production data analysis of the parent well provides fracture conductivity and surface area and formation permeability. Furthermore, reservoir simulation is tuned such that it can also match the pressure depletion map by adjusting the system permeability and fracture geometry of the parent well. The workflow of this study was applied to two field case from Montney formation in Western Canadian Sedimentary Basin. In Field Case 1, DFIT results from nine new wells were used to map the pressure depletion away from the toe fracture of a parent well (four wells toeing toward the parent well and five wells in the same direction as the parent). RTA and reservoir simulation are used to analyze the production data of the parent well qualitatively and quantitatively. The reservoir model is then used to match the pressure depletion map and the production data of the parent well and the outputs of the model includes hydraulic fracture half-lengths on both sides of the parent well, formation permeability, fracture surface area and fracture conductivity. In Field Case 2, the production data from an existing well and DFIT result from a new well toeing toward the existing wells were incorporated into a reservoir simulation model. The model outputs include system permeability and fracture surface area. It is recommended to try the method for more cases in a specific reservoir area to get a statistical understanding of the system permeability and fracture geometry for different completion designs. This study provides a practical and cost-effective approach for pressure depletion mapping using multi-well DFITs and the analysis of the resulting data using reservoir simulation and RTA. The study also encourages the practitioners to take every opportunity to run DFITs and gather pressure data from as many well as possible with focus on child wells.

A Novel Design Method for Optimizing the Diverter Dosage in Hydraulic Fracturing Using Three-Dimensionally Printed Fractures

2021 ◽  
Author(s):  
Meng Wang ◽  
Mingguang Che ◽  
Bo Zeng ◽  
Yi Song ◽  
Yun Jiang ◽  
...  
Keyword(s):  
Shale Gas ◽  
Design Method ◽  
Pressure Rise ◽  
Horizontal Wells ◽  
Optimization Method ◽  
Darcy Law ◽  
Hydraulic Fractures ◽  
Fracture Conductivity ◽  
Fracture Simulation ◽  
3D Printed

Abstract Application of diversion agents in temporarily plugging fracturing of horizontal wells of shale has becoming more and more popular. Nevertheless, the studies on determining the diverter dosage are below adequacy. A novel approach based on laboratory experiments, logging data, rock mechanics tests and fracture simulation was proposed to optimizing the dosage of diversion agents. The optimization model is based on the classic Darcy Law. A pair of 3D-printed rock plates with rugged faces was combined to simulate the coarse hydraulic fractures with the width of 2.0 ~ 7.0 mm. The mixture of the diversion agents and slickwater was dynamically injected to simulate the fracture in Temco fracture conductivity system to mimic the practical treatment to temporarily plugging the fracture. The permeability of the temporary plugging zone in the 3D-printed fractures was measured in order to optimize the dosage of the selected diversion agents. The value of Pnet (also the value of ΔP in Darcy Formula) required for creation of new branched fractures was determined using the Warpinski-Teufel Failure Rules. The hydraulic fractures of target stages were simulated to obtain the widths and heights. The experimental results proved that the selected suite of the diversion agents can temporarily plug the 3D-printed fractures of 2.0 ~ 7.0 mm with blocking pressure up to 15 MPa. The measured permeability of the resulting plugging zones was 0.724 ~ 0.933 D (averaging 0.837 D). The value of Pnet required for creation of branched fractures in shale of WY area (main shale gas payzone of China) was determined as 0.4 ~ 15.6 MPa (averaging 7.9 MPa) which means the natural fractures and/or weak planes with approaching angle less than 70° could be opened to increase the SRV. The typical dosage of the diversion agents used for one stage of the horizontal wells (averaging TVD 3600 m) was calculated as 232 ~ 310 kg. The optimization method was applied to the design job of temporarily plugging fracturing of two shale gas wells. The observed surface pressure rise after injection of diversion agents was 0.6 ~ 11.7 MPa (averaging 4.7 MPa) and the monitored microseismic events of the test stages were 37% more than those of the offset stages.

scholarly journals Estimating Unpropped-Fracture Conductivity and Fracture Compliance From Diagnostic Fracture-Injection Tests

SPE Journal ◽  
2018 ◽  
Vol 23 (05) ◽  
pp. 1648-1668 ◽  
Author(s):  
HanYi Wang ◽  
Mukul M. Sharma
Keyword(s):  
Earth Science ◽  
Mathematical Framework ◽  
Field Scale ◽  
Time Data ◽  
Fracture Conductivity ◽  
Reliable Technique ◽  
Fracture Width ◽  
In Situ Conditions ◽  
Fracture Closure

Summary A new method is proposed to estimate the compliance and conductivity of induced unpropped fractures as a function of the effective stress acting on the fracture from diagnostic-fracture-injection-test (DFIT) data. A hydraulic-fracture resistance to displacement and closure is described by its compliance (or stiffness). Fracture compliance is closely related to the elastic, failure, and hydraulic properties of the rock. Quantifying fracture compliance and fracture conductivity under in-situ conditions is crucial in many Earth-science and engineering applications but is very difficult to achieve. Even though laboratory experiments are used often to measure fracture compliance and conductivity, the measurement results are influenced strongly by how the fracture is created, the specific rock sample obtained, and the degree to which it is preserved. As such, the results may not be representative of field-scale fractures. During the past 2 decades, the DFIT has evolved into a commonly used and reliable technique to obtain in-situ stresses, fluid-leakoff parameters, and formation permeability. The pressure-decline response across the entire duration of a DFIT reflects the process of fracture closure and reservoir-flow capacity. As such, it is possible to use these data to quantify changes in fracture conductivity as a function of stress. In this paper, we present a single, coherent mathematical framework to accomplish this. We show how each factor affects the pressure-decline response, and the effects of previously overlooked coupled mechanisms are examined and discussed. Synthetic and field-case studies are presented to illustrate the method. Most importantly, a new specialized plot (normalized system-stiffness plot) is proposed, which not only provides clear evidence of the existence of a residual fracture width as a fracture is closing during a DFIT, but also allows us to estimate fracture-compliance (or stiffness) evolution, and infer unpropped fracture conductivity using only DFIT pressure and time data alone. It is recommended that the normalized system-stiffness plot (NS plot) be used as a standard practice to complement the G-function or square-root-of-time plot and log-log plot because it provides very valuable information on fracture-closure behavior and the properties of fracture-surface roughness at a field-scale, information that cannot be obtained by any other means.

A new approach to evaluate the performance of partially propped hydraulic fractures

2013 ◽  
Vol 53 (1) ◽  
pp. 355 ◽  
Author(s):  
Luiz Bortolan Neto ◽  
Aditya Khanna ◽  
Andrei Kotousov
Keyword(s):  
Sensitivity Study ◽  
Economic Benefits ◽  
Productivity Index ◽  
Hydraulic Fractures ◽  
Fracture Geometry ◽  
Fracture Conductivity ◽  
New Approach ◽  
Fracture Length ◽  
Compressive Stresses ◽  
Initial Fracture

A new approach for evaluating the performance of hydraulic fractures that are partially packed with proppant (propping agent) particles is presented. The residual opening of the partially propped fracture is determined as a function of the initial fracture geometry, the propped length of the fracture, the compressive rock stresses, the elastic properties of the rock, and the compressibility of the proppant pack. A mathematical model for fluid flow towards the fracture is developed, which incorporates the effects of the residual opening profile of the fracture and the high conductivity of the unpropped fracture length. The residual opening profile of the fracture is calculated for a particular case where the proppant pack is nearly rigid and there is no closure of the fracture faces due to the confining (compressive) stresses. A sensitivity study is performed to demonstrate the dependence of the well productivity index on the propped length of the fracture, the proppant pack permeability, and the dimensionless fracture conductivity. The sensitivity study suggests that the residual opening of a fracture has a significant impact on production, and that partially propped fractures can be more productive than fully propped fractures. Application of this new approach can lead to economic benefits.

Numerical Simulation of Proppant Transportation in Hydraulic Fracture Based on DDPM-KTGF Model

2019 ◽  
Author(s):  
Yan Zhang ◽  
Xiaobing Lu ◽  
Xuhui Zhang ◽  
Peng Li
Keyword(s):  
Volume Fraction ◽  
Engineering Application ◽  
Gas Production ◽  
Particle Model ◽  
Hydraulic Fractures ◽  
Single Fracture ◽  
Particulate Flows ◽  
Gas Reservoirs ◽  
Two Phase ◽  
Discrete Particle Model

Abstract Hydraulic fracturing is an efficient way to improve the conductivity of the tight oil or gas reservoirs. Proppant transportation in hydraulic fractures need to be investigated because the proppant distribution directly affects the oil or gas production. In this paper, the dense discrete particle model (DDPM) combined with the kinetic theory of granular flow (KTGF) are used to investigate the proppant transportation in a single fracture. In this model, the effects of proppant volume fraction, proppant-water interaction, proppant-proppant collision, and proppant size distribution are considered. The proppant-proppant collision is derived from the proppant stress tensor. This model is applicable from dilute to dense particulate flows. The simulated results are similar to the experimental data from other researchers. In further study, the two-phase flow in the cross fractures will be considered for engineering application.

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