scholarly journals A multi-perforation staged fracturing experimental study on hydraulic fracture initiation and propagation

2020 ◽  
Vol 38 (6) ◽  
pp. 2466-2484
Author(s):  
Jianguang Wei ◽  
Saipeng Huang ◽  
Guangwei Hao ◽  
Jiangtao Li ◽  
Xiaofeng Zhou ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Oil And Gas ◽  
Fracture Initiation ◽  
Fracture Network ◽  
Hydraulic Fractures ◽  
Breakdown Pressure ◽  
Tight Sandstone ◽  
Heterogeneous Samples ◽  
Initiation And Propagation

Hydraulic fracture initiation and propagation are extremely important on deciding the production capacity and are crucial for oil and gas exploration and development. Based on a self-designed system, multi-perforation cluster-staged fracturing in thick tight sandstone reservoir was simulated in the laboratory. Moreover, the technology of staged fracturing during casing completion was achieved by using a preformed perforated wellbore. Three hydraulic fracturing methods, including single-perforation cluster fracturing, multi-perforation cluster conventional fracturing and multi-perforation cluster staged fracturing, were applied and studied, respectively. The results clearly indicate that the hydraulic fractures resulting from single-perforation cluster fracturing are relatively simple, which is difficult to form fracture network. In contrast, multi-perforation cluster-staged fracturing has more probability to produce complex fractures including major fracture and its branched fractures, especially in heterogeneous samples. Furthermore, the propagation direction of hydraulic fractures tends to change in heterogeneous samples, which is more likely to form a multi-directional hydraulic fracture network. The fracture area is greatly increased when the perforation cluster density increases in multi-perforation cluster conventional fracturing and multi-perforation cluster-staged fracturing. Moreover, higher perforation cluster densities and larger stage numbers are beneficial to hydraulic fracture initiation. The breakdown pressure in homogeneous samples is much higher than that in heterogeneous samples during hydraulic fracturing. In addition, the time of first fracture initiation has the trend that the shorter the initiation time is, the higher the breakdown pressure is. The results of this study provide meaningful suggestions for enhancing the production mechanism of multi-perforation cluster staged fracturing.

scholarly journals Effect of Joint Geometrical Parameters on Hydraulic Fracture Network Propagation in Naturally Jointed Shale Reservoirs

Geofluids ◽  
2018 ◽  
Vol 2018 ◽  
pp. 1-23 ◽  
Author(s):  
Zhaohui Chong ◽  
Qiangling Yao ◽  
Xuehua Li
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Fracture Network ◽  
Hydraulic Fractures ◽  
Geometrical Parameters ◽  
Breakdown Pressure ◽  
Opening Mode ◽  
Hydraulic Fracture Network ◽  
Shale Reservoirs ◽  
Network Pattern

The presence of a significant amount of discontinuous joints results in the inhomogeneous nature of the shale reservoirs. The geometrical parameters of these joints exert effects on the propagation of a hydraulic fracture network in the hydraulic fracturing process. Therefore, mechanisms of fluid injection-induced fracture initiation and propagation in jointed reservoirs should be well understood to unleash the full potential of hydraulic fracturing. In this paper, a coupled hydromechanical model based on the discrete element method is developed to explore the effect of the geometrical parameters of the joints on the breakdown pressure, the number and proportion of hydraulic fractures, and the hydraulic fracture network pattern generated in shale reservoirs. The microparameters of the matrix and joint used in the shale reservoir model are calibrated through the physical experiment. The hydraulic parameters used in the model are validated through comparing the breakdown pressure derived from numerical modeling against that calculated from the theoretical equation. Sensitivity analysis is performed on the geometrical parameters of the joints. Results demonstrate that the HFN pattern resulting from hydraulic fracturing can be roughly divided into four types, i.e., crossing mode, tip-to-tip mode, step path mode, and opening mode. As β (joint orientation with respect to horizontal principal stress in plane) increases from 0° to 15° or 30°, the hydraulic fracture network pattern changes from tip-to-tip mode to crossing mode, followed by a gradual decrease in the breakdown pressure and the number of cracks. In this case, the hydraulic fracture network pattern is controlled by both γ (joint step angle) and β. When β is 45° or 60°, the crossing mode gains dominance, and the breakdown pressure and the number of cracks reach the lowest level. In this case, the HFN pattern is essentially dependent on β and d (joint spacing). As β reaches 75° or 90°, the step path mode is ubiquitous in all shale reservoirs, and the breakdown pressure and the number of the cracks both increase. In this case, β has a direct effect on the HFN pattern. In shale reservoirs with the same β, either decrease in k (joint persistency) and e (joint aperture) or increase in d leads to the increase in the breakdown pressure and the number of cracks. It is also found that changes in d and e result in the variation in the proportion of different types of hydraulic fractures. The opening mode of the hydraulic fracture network pattern is observed when e increases to 1.2 × 10−2 m.

Fracture Initiation and Propagation in a Deep Shale Gas Reservoir Subject to an Alternating-Fluid-Injection Hydraulic-Fracturing Treatment

SPE Journal ◽  
2019 ◽  
Vol 24 (04) ◽  
pp. 1839-1855 ◽  
Author(s):  
Bing Hou ◽  
Zhi Chang ◽  
Weineng Fu ◽  
Yeerfulati Muhadasi ◽  
Mian Chen
Keyword(s):  
Hydraulic Fracturing ◽  
Shale Gas ◽  
Fracture Initiation ◽  
Fluid Injection ◽  
Hydraulic Fractures ◽  
Stress Difference ◽  
Gas Reservoirs ◽  
Complex Fracture ◽  
Initiation And Propagation

Summary Deep shale gas reservoirs are characterized by high in-situ stresses, a high horizontal-stress difference (12 MPa), development of bedding seams and natural fractures, and stronger plasticity than shallow shale. All of these factors hinder the extension of hydraulic fractures and the formation of complex fracture networks. Conventional hydraulic-fracturing techniques (that use a single fluid, such as guar fluid or slickwater) do not account for the initiation and propagation of primary fractures and the formation of secondary fractures induced by the primary fractures. For this reason, we proposed an alternating-fluid-injection hydraulic-fracturing treatment. True triaxial hydraulic-fracturing tests were conducted on shale outcrop specimens excavated from the Shallow Silurian Longmaxi Formation to study the initiation and propagation of hydraulic fractures while the specimens were subjected to an alternating fluid injection with guar fluid and slickwater. The initiation and propagation of fractures in the specimens were monitored using an acoustic-emission (AE) system connected to a visual display. The results revealed that the guar fluid and slickwater each played a different role in hydraulic fracturing. At a high in-situ stress difference, the guar fluid tended to open the transverse fractures, whereas the slickwater tended to activate the bedding planes as a result of the temporary blocking effect of the guar fluid. On the basis of the development of fractures around the initiation point, the initiation patterns were classified into three categories: (1) transverse-fracture initiation, (2) bedding-seam initiation, and (3) natural-fracture initiation. Each of these fracture-initiation patterns had a different propagation mode. The alternating-fluid-injection treatment exploited the advantages of the two fracturing fluids to form a large complex fracture network in deep shale gas reservoirs; therefore, we concluded that this method is an efficient way to enhance the stimulated reservoir volume compared with conventional hydraulic-fracturing technologies.

Some challenges in hydraulic fracturing of tight gas reservoirs: an experimental study

2011 ◽  
Vol 51 (1) ◽  
pp. 499 ◽  
Author(s):  
Vamegh Rasouli ◽  
Mohammad Sarmadivaleh ◽  
Amin Nabipour
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Oil And Gas ◽  
Interaction Mechanism ◽  
Natural Fracture ◽  
Gas Reservoirs ◽  
Tight Sandstone ◽  
True Triaxial ◽  
Rock Types ◽  
Interface Parameters

Hydraulic fracturing is a technique used to enhance production from low quality oil and gas reservoirs. This approach is the key technique specifically in developing unconventional reservoirs, such as tight formations and shale gas. During its propagation, the hydraulic fracture may arrive at different interfaces. The mechanical properties and bounding quality of the interface as well as insitu stresses are among the most significant parameters that determine the interaction mechanism, i.e. whether the hydraulic fracture stops, crosses or experiences an offset upon its arrival at the interface. The interface could be a natural fracture, an interbed, layering or any other weakness feature. In addition to the interface parameters, the rock types of the two sides of the interface may affect the interaction mechanism. To study the interaction mechanism, hydraulic fracturing experiments were conducted using a true triaxial stress cell on two cube samples of 15 cm. Sample I had a sandstone block in the middle surrounded by mortar, whereas in sample II the location of mortar and tight sandstone blocks were changed. The results indicated that besides the effect of the far field stress magnitudes, the heterogeneity of the formation texture and interface properties can have a dominant effect in propagation characteristics of an induced fracture.

Time-Dependent Initiation of Multiple Hydraulic Fractures in a Formation With Varying Stresses and Strength

SPE Journal ◽  
2015 ◽  
Vol 20 (06) ◽  
pp. 1317-1325 ◽  
Author(s):  
Andrew P. Bunger ◽  
Guanyi Lu
Keyword(s):  
Tensile Strength ◽  
Hydraulic Fracture ◽  
Fracture Initiation ◽  
Time Frame ◽  
Hydraulic Fractures ◽  
Static Fatigue ◽  
Breakdown Pressure ◽  
Initiation Point ◽  
Delayed Failure ◽  
Wellbore Pressure

Summary The premise of classical hydraulic-fracture-breakdown models is that hydraulic-fracture growth can only start when the wellbore pressure reaches a critical value that is sufficient to overcome the tensile strength of the rock. However, rocks are well-known to exhibit static fatigue; that is, delayed failure at stresses less than the tensile strength. In this paper, we explore the consequences of delayed failure on axially oriented initiation of multiple hydraulic fractures. Specifically, given a certain breakdown pressure, we investigate the conditions under which subsequent hydraulic fracture(s) can begin within the time frame of a stimulation treatment in regions of higher stress and/or strength because of delayed-failure mechanisms. The results show that wells completed in shallower formations are more sensitive to variations in strength, whereas wells completed in deeper formations are more sensitive to variations in stress. Furthermore, cases in which all hydraulic fractures break down according to the same pressurization regime—that is, all are “fast” (nonfluid-penetrating) pressurization or else all are “slow” (uniformly pressurized fluid-penetrating) pressurization cases—are highly sensitive to small stress/strength variability. On the other hand, if the first hydraulic-fracture initiation is in the “fast”-pressurization regime and subsequent fracture(s) are in the “slow”-pressurization regime, then the system is robust to a much-higher degree of variability in stress/strength. Practically, this work implies that methods aimed at moderately reducing the variability in stress/strength among the possible initiation points (i.e., perforation clusters) within a particular stage can have a strong effect on whether multiple hydraulic fractures will begin. In addition, this analysis implies that pumping strategies that encourage “fast,” nonpenetrative breakdown of the first initiation point followed by the opportunity for fluid-penetrating, “slow” breakdown of subsequent initiation points could be effective at encouraging multiple-hydraulic-fracture initiation.

scholarly journals Three-Dimensional Ultrasonic Imaging and Acoustic Emission Monitoring of Hydraulic Fractures in Tight Sandstone

2021 ◽  
Vol 11 (19) ◽  
pp. 9352
Author(s):  
Wei Zhu ◽  
Shangxu Wang ◽  
Xu Chang ◽  
Hongyu Zhai ◽  
Hezhen Wu
Keyword(s):  
Acoustic Emission ◽  
Hydraulic Fracturing ◽  
Rock Mechanics ◽  
Oil And Gas ◽  
Ordos Basin ◽  
Water Injection ◽  
Three Dimensional ◽  
Hydraulic Fractures ◽  
Tight Sandstone ◽  
Fracturing Process

Hydraulic fracturing is an important means for the development of tight oil and gas reservoirs. Laboratory rock mechanics experiments can be used to better understand the mechanism of hydraulic fracture. Therefore, in this study we carried out hydraulic fracturing experiments on Triassic Yanchang Formation tight sandstone from the Ordos Basin, China. Sparse tomography was used to obtain ultrasonic velocity images of the sample during hydraulic fracturing. Then, combining the changes in rock mechanics parameters, acoustic emission activities, and their spatial position, we analyzed the hydraulic fracturing process of tight sandstone under high differential stress in detail. The experimental results illuminate the fracture evolution processes of hydraulic fracturing. The competition between stress-induced dilatancy and fluid flow was observed during water injection. Moreover, the results prove that the “seismic pump” mode occurs in the dry region, while the “dilation hardening” and “seismic pump” modes occur simultaneously in the partially saturated region; that is to say, the hydraulic conditions dominate the failure mode of the rock.

scholarly journals PARAMETER PREDICTION OF HYDRAULIC FRACTURE FOR TIGHT RESERVOIR BASED ON MICRO-SEISMIC AND HISTORY MATCHING

Fractals ◽  
2018 ◽  
Vol 26 (02) ◽  
pp. 1840009 ◽  
Author(s):  
KAI ZHANG ◽  
XIAOPENG MA ◽  
YANLAI LI ◽  
HAIYANG WU ◽  
CHENYU CUI ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
History Matching ◽  
Seismic Source ◽  
Fracture Network ◽  
Distribution Area ◽  
Hydraulic Fractures ◽  
Discrete Fracture Model ◽  
Tight Reservoir ◽  
Seismic Source Location

Hydraulic fracturing is an important measure for the development of tight reservoirs. In order to describe the distribution of hydraulic fractures, micro-seismic diagnostic was introduced into petroleum fields. Micro-seismic events may reveal important information about static characteristics of hydraulic fracturing. However, this method is limited to reflect the distribution area of the hydraulic fractures and fails to provide specific parameters. Therefore, micro-seismic technology is integrated with history matching to predict the hydraulic fracture parameters in this paper. Micro-seismic source location is used to describe the basic shape of hydraulic fractures. After that, secondary modeling is considered to calibrate the parameters information of hydraulic fractures by using DFM (discrete fracture model) and history matching method. In consideration of fractal feature of hydraulic fracture, fractal fracture network model is established to evaluate this method in numerical experiment. The results clearly show the effectiveness of the proposed approach to estimate the parameters of hydraulic fractures.

Geomechanical Template for Distributed Acoustic Sensing Strain Patterns during Hydraulic Fracturing

SPE Journal ◽  
2021 ◽  
pp. 1-12
Author(s):  
Yunhui Tan ◽  
Shugang Wang ◽  
Margaretha C. M. Rijken ◽  
Kelly Hughes ◽  
Ivan Lim Chen Ning ◽  
...  
Keyword(s):  
Finite Element ◽  
Hydraulic Fracturing ◽  
Strain Rate ◽  
Hydraulic Fracture ◽  
Strain Field ◽  
Low Frequency ◽  
Fracture Propagation ◽  
Fracture Network ◽  
Hydraulic Fractures ◽  
Distributed Acoustic Sensing

Summary Recently more distributed acoustic sensing (DAS) data have been collected during hydraulic fracturing in shale. Low-frequency DAS signals show patterns that are intuitively consistent with the understanding of the strain field around hydraulic fractures. This study uses a fracture simulator combined with a finite element solver to further understand the various patterns of the strain field caused by hydraulic fracturing. The results can serve as a “type-curve” template for the further interpretation of cross-well strain field plots. Incorporating detailed pump schedule and fracturing fluid/proppant properties, we use a hydraulic fracture simulator to generate fracture geometries, which are then passed to a finite element solver as boundary conditions for elastic-static calculation of the strain field. Because the finite element calculated strain is a tensor, it needs to be projected along the monitoring well trajectory to be comparable with the DAS strain, which is uniaxial. Moreover, the calculated strain field is transformed into a time domain using constant fracture propagation velocity. Strain rate is further derived from the simulated strain field using differentiation along the fracture propagation direction. Scenarios including a single planar hydraulic fracture, a single fracture with a discrete fracture network (DFN), and multiple planar hydraulic fractures in both vertical and horizontal directions were studied. The scenarios can be differentiated in the strain patterns on the basis of the finite element simulation results. In general, there is a tensile heart-shaped zone in front of the propagating fracture tip shown along the horizontal strain direction on both strain and strain rate plots. On the sides, there are compressional zones parallel to the fracture. The strain field projects beyond the depth where the hydraulic fracture is present. Patterns from strain rate can be used to distinguish whether the fracture is intersecting the fiber. Along the vertical direction, the transition zone depicts the upper boundary of the fracture. A complex fracture network with DFN shows a much more complex pattern compared with a single planar fracture. Multiple planar fractures show polarity reversals in horizontal fiber because of interactions between fractures. Data from the Hydraulic Fracturing Test Site 2 (HFTS2) experiment were used to validate the simulated results. The application of the study is to provide a template to better interpret hydraulic fracture characteristics using low-frequency DAS strain-monitoring data. To our understanding, there are no comprehensive templates for engineers to understand the strain signals from cross-well fiber monitoring. The results of this study will guide engineers toward better optimization of well spacing and fracturing design to minimize well interference and improve efficiency.

scholarly journals Study on Propagation Behaviors of Hydraulic Fracture Network in Tight Sandstone Formation with Closed Cemented Natural Fractures

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-22
Author(s):  
Jun Zhang ◽  
Yu-Wei Li ◽  
Wei Li ◽  
Zi-Jie Chen ◽  
Yuan Zhao ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Fracture Network ◽  
In Situ Stress ◽  
Injection Rate ◽  
Fluid Viscosity ◽  
Tight Sandstone ◽  
Propagation Behavior ◽  
Sandstone Formation

Natural fractures in tight sandstone formation play a significant role in fracture network generation during hydraulic fracturing. This work presents an experimental model of tight sandstone with closed cemented preexisting fractures. The influence of closed cemented fractures’ (CCF) directions on the propagation behavior of hydraulic fracture (HF) is studied based on the hydraulic fracturing experiment. A field-scaled numerical model used to simulate the propagation of HF is established based on the flow-stress-damage (FSD) coupled method. This model contains the discrete fracture network (DFN) generated by the Monte-Carlo method and is used to investigate the effects of CCFs’ distribution, CCFs’ strength, and in-situ stress anisotropy, injection rate, and fluid viscosity on the propagation behavior of fracture network. The results show that the distribution direction of CCFs is critical for the formation of complex HFs. When the angle between the horizontal maximum principal stress direction and the CCFs is in the range of 30° to 60°, the HF network is the most complex. There are many kinds of compound fracture propagation patterns, such as crossing, branching, and deflection. The increase of CCFs’ strength is not conducive to the generation of branched and deflected fractures. When the in-situ stress difference ranges from 3 MPa to 6 MPa, the HF network’s complexity and propagation range can be guaranteed simultaneously. The increase in the injection rate will promote the formation of the complex HF network. The proper increase of fracturing fluid viscosity can promote HF’s propagation. However, when the viscosity is too high, the complex HFs only appear around the wellbore. The research results can provide new insights for the hydraulic fracturing optimization design of naturally fractured tight sandstone formation.

scholarly journals Review of pseudo-three-dimensional modeling approaches in hydraulic fracturing

2021 ◽  
Author(s):  
Hai T. Nguyen ◽  
Jang Hyun Lee ◽  
Khaled A. Elraies
Keyword(s):  
Hydraulic Fracture ◽  
Oil And Gas ◽  
Three Dimensional ◽  
Network Models ◽  
Fracture Network ◽  
Injection Rate ◽  
Height Growth ◽  
Early Developmental Stage ◽  
Hydraulic Fractures ◽  
Equilibrium Height

AbstractIn the field of hydraulic fracture modeling, the pseudo-three-dimensional (P3D) approach is an efficient and practical computational tool serving as a compromise between two-dimensional and planar three-dimensional models. This review discusses the P3D modeling approach from its early developmental stage in the 1980s to the present. The evolution of P3D modeling is drawn over time based on the major differences in the governing formulation and assumptions considered by each model. The problems of equilibrium height growth and vertical viscous fluid resistance (i.e., non-equilibrium height growth) emphasize the primary differences among these models. Besides, the P3D-based complex fracture network models for shale oil and gas reservoirs accounting for the interaction between preexisting natural fractures and induced hydraulic fractures are discussed. Finally, in the application section, several simulations are reported to demonstrate the validation of the P3D numerical algorithm by comparing it with the Perkins–Kern–Nordgren (PKN) large and small asymptotic solutions, as well as the effect of time-dependent variable injection rates on the hydraulic fracture propagation. The results showed a good matching between P3D and PKN solutions and a significant effect of the wellbore variable injection rate on the evolution of the fracture length.

The relation between stimulated shear fractures and production in the Barnett Shale: Implications for unconventional oil and gas reservoirs

Geophysics ◽  
2019 ◽  
Vol 84 (6) ◽  
pp. B461-B469 ◽  
Author(s):  
Alex Hakso ◽  
Mark Zoback
Keyword(s):  
Hydraulic Fracturing ◽  
Oil And Gas ◽  
Shear Fracture ◽  
Fracture Network ◽  
Early Years ◽  
Barnett Shale ◽  
Hydraulic Fractures ◽  
Low Permeability ◽  
Distributed Temperature Sensing ◽  
Fracture Planes

Economic production from extremely low permeability unconventional reservoirs is accomplished through multistage slick water hydraulic fracturing, which generates opening-mode hydraulic fractures and induces shear slip on preexisting fractures in the surrounding formation. We have addressed the critical contribution of the stimulated shear fracture network on production. We found production decline curves from tens of thousands of wells in four unconventional plays in the U.S. (two oil and two gas). These data indicate that during the early years of production: (1) Production is dominated by linear flow from the extremely low permeability matrix into much more permeable fracture planes, (2) the rapid decrease in production rates is a natural consequence of pressure depletion in the matrix within several meters of the more permeable planes, and (3) the cumulative area of permeable fracture planes created during stimulation is an important factor affecting cumulative production. Using data from two case studies in the Barnett Shale, we estimate the area of the fracture network from the microseismicity generated during hydraulic fracturing operations. The data from one study demonstrates that the cumulative area of the shear fracture network is needed to match production data. With data from the other case study, we demonstrate that the relative fracture area created during each stage correlates well with the relative stage-by-stage production determined from distributed temperature sensing.

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