The Role of Rock Matrix Permeability in Controlling Hydraulic Fracturing in Sandstones

AbstractA concomitant effect of a hydraulic fracturing experimenting is frequently fluid permeation into the rock matrix, with the injected fluid permeating through the porous rock matrix (leak-off) rather than contributing to the buildup of borehole pressure, thereby slowing down or impeding the hydro-fracturing process. Different parameters, such as low fluid viscosity, low injection rate and high rock permeability, contribute to fluid permeation. This effect is particularly prominent in highly permeable materials, therefore, making sleeve fracturing tests (where an internal jacket separates the injected fluid in the borehole from the porous rock matrix) necessary to generate hydraulic fractures. The side effect, however, is an increase in pressure breakdown, which results in higher volume of injected fluid and in higher seismic activity. To better understand this phenomenon, we report data from a new comparative study from a suite of micro-hydraulic fracturing experiments on highly permeable and on low-permeability rock samples. Experiments were conducted in both sleeve fracture and direct fluid fracture modes using two different injection rates. Consistent with previous studies, our results show that hydraulic fracturing occurred only with low permeation, either due to the intrinsic low permeability or due to the presence of an inner silicon rubber sleeve. In particular, due to the presence of quasi-impermeable inner sleeve or borehole skin in the sleeve fracturing experiment, fracturing occurs, with the breakdown pressure supporting the linear elastic approach considering poroelastic effects, therefore, with low stress drop and consequently low microseismicity. Rock matrix permeability also controls the presence of precursory Acoustic Emission activity, as this is linked to the infiltration of fluids and consequent expansion of the pore space. Finally, permeability is shown to mainly control fracturing speed, because the permeation of fluid into the newly created fracture via the highly permeable rock matrix slows down its full development. The application of these results to the field may help to reduce induced seismicity and to conduct well stimulation in a more efficient way.

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Experience in Optimizing the Location and Parameters of Multistage Hydraulic Fractures for a Multilateral Well Based on Reservoir Simulation

10.2118/206541-ms ◽

2021 ◽

Author(s):

Vil Syrtlanov ◽

Yury Golovatskiy ◽

Konstantin Chistikov ◽

Dmitriy Bormashov

Keyword(s):

Hydraulic Fracturing ◽

Reservoir Simulation ◽

Optimal Placement ◽

Hydraulic Fractures ◽

Low Permeability ◽

Advantages And Disadvantages ◽

Modeling Methods ◽

Multistage Hydraulic Fracturing ◽

Determination Of Parameters

Abstract This work presents the approaches used for the optimal placement and determination of parameters of hydraulic fractures in horizontal and multilateral wells in a low-permeability reservoir using various methods, including 3D modeling. The results of the production rate of a multilateral dualwellbore well are analyzed after the actual hydraulic fracturing performed on the basis of calculations. The advantages and disadvantages of modeling methods are evaluated, recommendations are given to improve the reliability of calculations for models with hydraulic fracturing (HF)/ multistage hydraulic fracturing (MHF).

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Fracturing in low-permeability soils for remediation of contaminated ground

Canadian Geotechnical Journal ◽

10.1139/t00-097 ◽

2001 ◽

Vol 38 (2) ◽

pp. 316-327 ◽

Cited By ~ 14

Author(s):

Ron CK Wong ◽

Marolo C Alfaro

Keyword(s):

Electrical Resistivity ◽

Hydraulic Fracturing ◽

Electrical Resistivity Tomography ◽

Soil Formation ◽

Test Facility ◽

Hydraulic Fractures ◽

Low Permeability ◽

Resistivity Tomography ◽

Vertical Well ◽

Actual Fracture

This paper presents a field study on hydraulic fracturing for in situ remediation of contaminated ground. Sand-propped hydraulic fractures were placed from vertical and horizontal wells at a test facility. Field excavations were conducted to expose the fractures and inspect their distribution and geometry. Fractures that were mapped by field excavation were found to be near horizontal, implying that the soil formation is overconsolidated. It was also observed that the sand "proppant" was thicker at locations where the soil layers were relatively weak or contained weak fissures. Electrical resistivity tomography (ERT) was also conducted in an attempt to map the fractures. There was no indication that fractures were being mapped by this geophysical technique. Fracture mapping based on tiltmeter data analyses conformed closely with the actual fracture placement in the vertical well but did not properly predict the actual fracture placement in the horizontal well.Key words: hydraulic fracturing, field test, low-permeability soil, electrical resistivity tomography, tiltmeters, horizontal well, vertical well.

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

Applied Sciences ◽

10.3390/app11199352 ◽

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.

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An Efficient Numerical Hybrid Model for Multiphase Flow in Deformable Fractured-Shale Reservoirs

SPE Journal ◽

10.2118/191122-pa ◽

2018 ◽

Vol 23 (04) ◽

pp. 1412-1437 ◽

Cited By ~ 15

Author(s):

Xia Yan ◽

ZhaoQin Huang ◽

Jun Yao ◽

Yang Li ◽

Dongyan Fan ◽

...

Keyword(s):

Hydraulic Fracturing ◽

Hybrid Model ◽

Hydraulic Fractures ◽

Fluid Exchange ◽

Flow Process ◽

Numerical Examples ◽

Fracturing Process ◽

The Matrix ◽

Shale Reservoirs ◽

Porosity Model

Summary After hydraulic fracturing, a shale reservoir usually has multiscale fractures and becomes more stress-sensitive. In this work, an adaptive hybrid model is proposed to simulate hydromechanical coupling processes in such fractured-shale reservoirs during the production period (i.e., the hydraulic-fracturing process is not considered and cannot be simulated). In our hybrid model, the single-porosity model is applied in the region outside the stimulated reservoir volume (SRV), and the matrix and natural/induced fractures in the SRV region are modeled using a double-porosity model that can accurately simulate the matrix/fracture fluid exchange during the entire transient period. Meanwhile, the fluid flow in hydraulic fractures is modeled explicitly with the embedded-discrete-fracture model (EDFM), and a stabilized extended-finite-element-method (XFEM) formulation using the polynomial-pressure-projection (PPP) technique is applied to simulate mechanical processes. The developed stabilized XFEM formulation can avoid the displacement oscillation on hydraulic-fracture interfaces. Then a modified fixed-stress sequential-implicit method is applied to solve the hybrid model, in which mixed-space discretization [i.e., finite-volume method (FVM) for flow process and stabilized XFEM for geomechanics] is used. The robustness of the proposed model is demonstrated through several numerical examples. In conclusion, several key factors for gas exploitation are investigated, such as adsorption, Klinkenberg effect, capillary pressure, and fracture deformation. In this study, all the numerical examples are 2D, and the gravity effect is neglected in these simulations. In addition, we assume there is no oil phase in the shale reservoirs, thus the gas/water two-phase model is used to simulate the flow in these reservoirs.

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FEATURES OF PROPAGATION OF HYDRAULIC FRACTURES IN STRATIFIED ROCK MASS

Interexpo GEO-Siberia ◽

10.33764/2618-981x-2021-2-4-190-197 ◽

2021 ◽

Vol 2 (4) ◽

pp. 190-197

Author(s):

Evgeny N. Sher

Keyword(s):

Rock Mass ◽

Hydraulic Fracturing ◽

Hydraulic Fractures ◽

Fluid Viscosity ◽

External Compression ◽

Governing Factor ◽

Stress States ◽

Stratified Rock ◽

Stratified Rock Mass ◽

Tension Strength

In hydraulic fracturing commonly used in mining, it is important to determine the shapes and sizes of created fractures. The governing factor in this case is the structure of rock mass which is often stratified. This study analyzes the influence of strengths of the layers and their stress states on the shapes of the growing fractures. Numerical modeling shows that in hydraulic fracturing with low-viscous fluids, fractures grow mostly in a layer having lower tension or compression strengths. The calculations carried out for the analyzed cases provide the values of tension strength and external compression for hydraulic fractures to grow only in one layer. It is shown that the increase in the breakdown fluid viscosity weakens this effect.

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Zipper Fracturing of Horizontal Cluster Wells: Game Changing Unconventional Fracturing in UAE

10.2118/207523-ms ◽

2021 ◽

Author(s):

Yang Wu ◽

Ole Sorensen ◽

Nabila Lazreq ◽

Yin Luo ◽

Tomislav Bukovac ◽

...

Keyword(s):

Hydraulic Fracturing ◽

United Arab Emirates ◽

Shale Gas ◽

New Technology ◽

Operational Efficiency ◽

Gas Production ◽

Hydraulic Fractures ◽

Fluid Viscosity ◽

Fracture Width ◽

Friction Reducer

Abstract Following the increase in demand for natural gas production in the United Arab Emirates (UAE), unconventional hydraulic fracturing in the country has grown exponentially and with it the demand for new technology and efficiency to fast-track the process from fracturing to production. Diyab field has historically been a challenging field for fracturing given the high-pressure/high-temperature (HP/HT) conditions, presence of H2S, and the strike-slip to thrust faulting conditions. Meanwhile, operational efficiency is necessary for economic development of this shale gas reservoir. Hence "zipper fracturing" was introduced in UAE with modern technologies to enable both operational efficiency and reservoir stimulation performance. The introduction of zipper fracturing in UAE is considered a game changer as it shifted the focus from single-well fracturing to multiple well pads that allow for fracturing to take place in one well while the adjacent well is undergoing a pumpdown plug-and-perf operation using wireline. The overall setup of the zipper surface manifold allowed for faster transitions between the two wells; hence, it also rendered using large storage tanks a viable option since the turnover between stages would be short. Thus, two large modular tanks were installed and utilised to allow 160,000 bbl of water storage on site. Similarly, the use of high-viscosity friction reducer (HVFR) has directly replaced the common friction reducer additive or guar-based gel for shale gas operation. HVFR provides higher viscosity to carry larger proppant concentrations without the reservoir damage, and the flexibility and simplicity of optimizing fluid viscosity on-the-fly to ensure adequate fracture width and balance near-wellbore fracture complexity. Fully utilizing dissolvable fracture plugs was also applied to mitigate the risk of casing deformation and the subsequent difficulty of milling plugs after the fracturing treatment. Furthermore, fracture and completion design based on geologic modelling helped reduce risk of interaction between the hydraulic fractures and geologic abnormalities. With the application of advanced logistical planning, personnel proficiency, the zipper operation field process, clustered fracture placement, and the pump-down plug-and-perforation operation, the speed of fracturing reached a maximum of 4.5 stages per day, completing 67 stages in total between two wells placing nearly 27 million lbm of proppant across Hanifa formation. The maximum proppant per stage achieved was 606,000 lbm. The novelty of this project lies in the first-time application of zipper fracturing, as well as the first application of dry HVFR fracturing fluid and dissolvable fracturing plugs in UAE. These introductions helped in improving the overall efficiency of hydraulic fracturing in one of UAE's most challenging unconventional basins in the country, which is quickly demanding quicker well turnovers from fracturing to production.

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

Energies ◽

10.3390/en13051260 ◽

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.

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Fracture Propagation and Morphology Due to Non-Aqueous Fracturing: Competing Roles between Fluid Characteristics and In Situ Stress State

Minerals ◽

10.3390/min10050428 ◽

2020 ◽

Vol 10 (5) ◽

pp. 428

Author(s):

Yunzhong Jia ◽

Zhaohui Lu ◽

Hong Liu ◽

Jiehao Wang ◽

Yugang Cheng ◽

...

Keyword(s):

Carbon Dioxide ◽

Hydraulic Fracturing ◽

Fracture Propagation ◽

Horizontal Stress ◽

In Situ Stress ◽

Fluid Viscosity ◽

Low Viscosity ◽

Fracturing Process ◽

Fluid Characteristics

Non-aqueous or gaseous stimulants are alternative working fluids to water for hydraulic fracturing in shale reservoirs, which offer advantages including conserving water, avoiding clay swelling and decreasing formation damage. Hence, it is crucial to understand fluid-driven fracture propagation and morphology in shale formations. In this research, we conduct fracturing experiments on shale samples with water, liquid carbon dioxide, and supercritical carbon dioxide to explore the effect of fluid characteristics and in situ stress on fracture propagation and morphology. Moreover, a numerical model that couples rock property heterogeneity, micro-scale damage and fluid flow was built to compare with experimental observations. Our results indicate that the competing roles between fluid viscosity and in situ stress determine fluid-driven fracture propagation and morphology during the fracturing process. From the macroscopic aspect, fluid-driven fractures propagate to the direction of maximum horizontal stress direction. From the microscopic aspect, low viscosity fluid easily penetrates into pore throats and creates branches and secondary fractures, which may deflect the main fracture and eventually form the fracture networks. Our results provide a new understanding of fluid-driven fracture propagation, which is beneficial to fracturing fluid selection and fracturing strategy optimization for shale gas hydraulic fracturing operations.

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Hydraulic Fracture Propagation in Layered Rock: Experimental Studies of Fracture Containment

Society of Petroleum Engineers Journal ◽

10.2118/9878-pa ◽

1984 ◽

Vol 24 (01) ◽

pp. 19-32 ◽

Cited By ~ 107

Author(s):

Lawrence W. Teufel ◽

James A. Clark

Keyword(s):

Hydraulic Fracturing ◽

Hydraulic Fracture ◽

Horizontal Stress ◽

Hydraulic Fractures ◽

Low Permeability ◽

Fracture Treatment ◽

Gas Recovery ◽

Layered Rock ◽

Fracture Fluid ◽

Minimum Horizontal Stress

Abstract Fracture geometry is an important concern in the design of a massive hydraulic fracture for improved natural gas recovery from low-permeability reservoirs. Determination of the extent of vertical fracture growth and containment in layered rock, a priori, requires an improved understanding of the parameters that may control fracture growth across layer interfaces. We have conducted laboratory hydraulic fracture experiments and elastic finite element studies that show that at least two distinct geologic conditions can inhibit or contain the vertical growth of hydraulic fractures in layered rock:a weak interfacial shear strength of the layers andan increase in the minimum horizontal compressive stress in the bounding layers. The second condition is more important and more likely to occur at depth. Differences in elastic properties within a layered rock mass may be important-not as a containment barrier perse, but in the manner in which variations in elastic properties affect the vertical distribution of the minimum horizontal stress magnitude. These results suggest that improved fracture treatment designs and an assessment of the potential success of stimulations in low-permeability reservoirs can be made by determining the in-situ stress st ate in the producing interval and bounding formations before stimulation. If the bounding formations have a higher minimum horizontal stress, then one can optimize the fracture treatment and maximize the ratio of productive formation fracture area to volume of fluid pumped by limiting bottomhole pressures to that of the bounding formation. Introduction In 1949, Clark introduced the concept of hydraulic fracturing to the petroleum industry. Since then, hydraulic fracture treatment to enhance oil and gas recovery in tight reservoir rocks has become standard practice. More recently, as a result of an increased need for better recovery techniques, massive hydraulic fracturing (MHF) has been used in low-permeability, gas-bearing sandstones in the Rock Mountain region and in Devonian shales of the Appalachian region, where it is uneconomical to retrieve gas in the conventional manner. Massive hydraulic fractures are designed to extend as much as 1000 m (3,281 ft) radially from the wellbore and generally require up to 1000 m3 (6,293 bbl) of fracture fluid. MHF has been developed by trial and error, and the results are uncertain in many situations. Some of these large-scale stimulation efforts have been successful, but others have been extremely disappointing failures. The reasons for these failures are not clear, but it seems likely that improved understanding of the fundamental mechanisms of hydraulic fracturing should suggest ways of improving the efficiency and reliability of the MHF stimulation technique or at least indicate where this technique can be applied successfully. Among the many technological problems encountered in MHF, one of the most important questions that must be answered properly to design a hydraulic fracture treatment for optimal gas recovery concerns the shape and overall geometry of the fracture. The question of fracture height and whether the hydraulic fracture will propagate into formations lying above and below the producing zone. When a fracture treatment is designed, the height of the fracture is the parameter about which the least is known, yet this influences all aspects of the design. A hydraulic fracture usually grows outward in a vertical plane and propagates above and below the packers as well as laterally away from the wellbore. Vertical propagation is undesirable whenever the fracturing is to be contained within a single stratigraphic interval. If the hydraulic fracture is not contained within the producing formation and propagates in both the vertical and lateral directions (an elliptical fracture), failure of the treatment can occur because the fracture fails to contact a sufficiently large area of the reservoir. Moreover, there is an effective loss of the expensive fracture fluid and proppant used to fracture the unproductive formations. An extreme example where the containment of a hydraulic fracture is essential is the case of developing a fracture in a gas-producing sandstone without fracturing through the underlying shale into another sandstone that is water-bearing. Therefore, it is of great economic importance to the gas industry to understand the parameters that can restrict the vertical propagation of massive hydraulic fractures. There are several parameters that are considered to have some effect on the vertical growth and possible containment of hydraulic fractures. SPEJ P. 19^

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Diffusivity-dependent fracturing processes and microseismic activity in granite

E3S Web of Conferences ◽

10.1051/e3sconf/202020502009 ◽

2020 ◽

Vol 205 ◽

pp. 02009

Author(s):

Catarina Baptista-Pereira ◽

Bruno Gonçalves da Silva

Keyword(s):

Hydraulic Fracturing ◽

Fluid Pressure ◽

Injection Rate ◽

Hydraulic Fractures ◽

Enhanced Geothermal Systems ◽

Geothermal Systems ◽

Rock Matrix ◽

Hydraulic Oil ◽

Permeability Enhancement ◽

Microseismic Activity

Enhanced Geothermal Systems have relied on hydraulic fracturing to increase the permeability of rock reservoirs. The permeability enhancement depends on the connectivity between new and existing fractures. This, in turn, depends to a large extent on the interaction between the rock and the fracturing fluid, which not only pressurizes existing and new fractures but also diffuses into the rock matrix. In this research, the effect of the diffusivity of hydraulic oil on the fracturing processes and microseismicity of unconfined prismatic granite specimens was experimentally evaluated using visual and acoustic emission monitoring. The tests consisted of injecting hydraulic oil into two pre-fabricated flaws at two rates (2 ml/min and 20 ml/min), kept constant in each test. The fluid pressure inside the flaws was increased until hydraulic fractures propagated and the fluid front growing from the pre-fabricated flaws was visually monitored throughout the tests. It was observed that the fracturing pressures and patterns were injection-rate-dependent, which shows that diffusivity and poro-elastic effects play an important role in the hydraulic fracturing processes of granite. A smaller fluid front was observed for the 20 ml/min injection rate, associated to a lower volume injected and to a higher fracturing pressure when compared to the 2 ml/min injection rate. This was interpreted to be caused by the different pore pressures that developed inside of the rock matrix, which are function of the fluid front size. Microseismic activity was observed throughout the tests, becoming more intense and localized near the flaws as one approached the end of the test (i.e. visible crack propagation). While microseismic events were observed outside the fluid front region, their density was significantly larger within this area, showing that fluid diffusivity may contribute to an intensification of the microseismic activity.

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