Study of hydraulic fracturing processes in shale formations with complex geological settings (original) (raw)
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We showed the capability of CZM in modeling multiple-stage field-scale fracturing.We successfully substituted the minimum horizontal stress with infinite elements.We proposed a procedure to characterize cohesive layers for hydraulic fracturing.Closely spaced fracturing can disconnect the older fractures from the wellbore.Our model provides a fundamental stress interaction and irregular fracture growth.Economic production from shale gas cannot be achieved by natural mechanisms alone; it requires technologies such as hydraulic fracturing in multiple stages along a horizontal wellbore. Developing numerical models for hydraulic fracturing is essential since a successful fracturing job in a shale formation cannot be generalized to another due to different shale characteristics, and restricted access to the field data acquisition. The cohesive zone model (CZM) identifies the plastic zone and softening effects at the fracture tip in a quasi-brittle rock such as shale, which leads to a more precise fracture geometry and injection pressure compared to those from linear elastic fracture mechanics. The incorporation of CZM in a fully coupled pore pressure–stress, finite element analysis provides a rigorous tool to include also the significant effect of in situ stresses in large matrix deformations on the fracturing fluid flow components, for instance leak-off. In this work, we modeled single and double-stage fracturing in a quasi-brittle shale layer using an improved CZM for porous media besides including the material softening effect and a new boundary condition treatment, using infinite elements connecting the domain of interest to the surrounding rock layers. Due to the lack of experimental data for the cohesive layer properties, we characterized the cohesive layer by sensitivity study on the stiffness, fracture initiation stress, and energy release rate. We demonstrated the significance of rock mechanical properties, pumping rate, viscosity, and leak-off in the pumping pressure, and fracture aperture. Moreover, we concluded that the stress shadowing effects of hydraulic fractures on each other majorly affects not only fractures’ length, height, aperture, and the required injection pressure, but also their connection to the injection spot. Also, we investigated two scenarios in the sequence of fracturing stages, simultaneous and sequential, with various fracture spacing and recommended the best scenario among them.Fracture opening and interaction for the double-stage, sequential fracturing case with 33-ft spacing and fracturing the left perforation before the right one. In Fig. b, the displacements are magnified 200 times for demonstration purposes. The opening contours are in meters.
Tehnicki vjesnik - Technical Gazette, 2016
Original scientific paper The fracture pattern of rock mass in shale gas reservoirs is one of the main factors affecting the efficiency of hydraulic fracturing. In this paper, physical experiments and numerical modelling were conducted to systematically investigate the effect of the in-situ stress and perforation angle on the hydraulic fracture initiation pressure and location, fracture propagation, and fracture pattern in a horizontal well drilled by Sinopec Corp. in Luojia area of Shengli Oilfield. A total of six different in-situ stress combinations and eight different perforation angles were considered for the stratified rock mass during the hydraulic fracturing. A summary of the fracture initiations and propagation, and the final fracture patterns induced by the hydraulic fracturing in the stratified rock masses reveals that, for the stratified rock masses with the same perforation angle, the larger the in-situ stress ratio (i.e. lower maximum horizontal principal stress when the vertical stress remains constant) is, the lower hydraulic pressure is required for hydraulic fracturing initiation and propagation. Moreover, it is found that, for the stratified rock mass under the same stress ratio, the hydraulic fracturing pressure in the case with a perforation angle of 30° is higher than that in all other cases. Furthermore, it is noted that the effect of the stratification on the hydraulic fracturing becomes weaker with the in-situ stress ratio increasing. It is finally concluded that the results from this study can provide important theoretical guidance for improving the hydraulic fracturing design in order to ensure the effective shale gas reservoir stimulations.
Applied Sciences, 2017
The aim of this study was to identify the influence of reservoir depth on reservoir rock mass breakdown pressure and the influence of reservoir depth and injecting fluid pressure on the flow ability of reservoirs before and after the hydraulic fracturing process. A series of fracturing tests was conducted under a range of confining pressures (1, 3, 5 and 7 MPa) to simulate various depths. In addition, permeability tests were conducted on intact and fractured samples under 1 and 7 MPa confining pressures to determine the flow characteristic variations upon fracturing of the reservoir, depending on the reservoir depth and injecting fluid pressure. N 2 permeability was tested under a series of confining pressures (5, 10, 15, 20 and 25 MPa) and injection pressures (1-10 MPa). According to the results, shale reservoir flow ability for gas movement may reduce with increasing injection pressure and reservoir depth, due to the Klinkenberg phenomenon and pore structure shrinkage, respectively. The breakdown pressure of the reservoir rock linearly increases with increasing reservoir depth (confining pressure). Interestingly, 81% permeability reduction was observed in the fractured rock mass due to high (25 MPa) confinement, which shows the importance of proppants in the fracturing process.
Geomechanical Principles of Hydraulic Fracturing Method in Unconventional Gas Reservoirs
International Journal of Engineering, 2018
Unconventional gas production from shale formation is not new to oil and gas experts worldwide. But our research work was built around hydraulic fracturing technique with focus on the Perkins Kern-Nordgren (PKN) 1972 hydraulic fracturing model(s). It is a very robust and flexible model that can be used on two major shale reservoirs (with the assumption of a fixed height and fracture fluid pressure). The essence was to compare detailed geo-mechanical parameters extracted from wire-line logs with Perkin-C model to select the right well as candidate for simulation. It aided in the prediction production of shale gas from tight shale formations. These also helped in reviewing safe and economical ways of obtaining clean energy sources. Based on similarities in well and formation properties our research team subjected IDJE-2 well (located in the Agbada shale Formation of Niger Delta, Nigeria) to various conditions, equations and assumptions proposed by the study model while also validating our results with the PENOBSCOT L-30 well, located in Canada (with existing profound results from stimulations). The PENOBSCOT L-30 well (Case 1) and IDJE-2 well (Case 2) were both subjected to same conditions, equations and assumptions as applicable to the study model to enable us compare and evaluate stimulation performances. But both cases tend to react differently. However the fluid behavior at constant injection time increases at about 99.64%. Whereas, the maximum width at wellbore shows that a constant increase of fracture width will yield an increase in propant permeability, tensile strength and Poisson's ratio for Case 1 & 2. Our research results show how rock properties can affect fracture geometry and expected production rates from stimulated shale reservoir formations.
Study on the Interaction Mechanism of Hydraulic Fracture and Natural Fracture in Shale Formation
Energies, 2019
Hydraulic fracturing is an essential technique for the development of shale gas, due to the low permeability in formation. Abundant natural fractures contained in a formation are indispensable for the development of a fracture network. In this paper, a damage-stress-seepage coupled hydraulic fracture expansion model, based on the extended finite element method, is established. The simulation results show that shear failure occurs when the hydraulic fracture interacts with a frictional natural fracture, while tensile failure occurs when it interacts with a cement natural fracture. Low interaction angles and high tensile strength of the rock are beneficial for the generation of a complex fracture network. Furthermore, under the same geological conditions and injection parameters, frictional natural fractures are more beneficial for the generation of a complex fracture network, when compared with cement natural fractures. This can not only effectively increase the propagation length of...
Analysis of Fracturing Pressure Data in Heterogeneous Shale Formations
Hydraulic Fracture Journal, 2014
Existing techniques for the interpretation of real-time fracturing data assumes that fracture propagation is a continuous power function of time, and that fractures propagate smoothly over time. This assumption implies that the formation is homogeneous. However, this assumption is not always accurate, as heterogeneities such as natural fractures exist, especially in shale. The presence of natural fractures is a vital factor in the productivity of shale oil and gas formations. When a hydraulic fracture intercepts a natural fracture, we believe one of two situations may take place depending on stress field, net pressure, orientation and the type of natural fracture: • The hydraulic fracture may cross the natural fracture and essentially continue to propagate, thus a smooth fracture propagation would be reflected in the real-time pressure data. • The natural fracture may dilate, allowing the fracturing fluid to enter the natural fracture. In this case, the propagation of the hydraulic fracture will cease in favor of the dilation of the natural fracture. Once the natural fracture is sufficiently dilated, the hydraulic fracture will resume propagation from the tip of the natural fracture(s). This paper presents a new real-time analysis technique of fracture propagation data that accounts for this intermittent hydraulic propagation in shale formations. This technique is an expansion of the existing technique originally developed by Nolte and Smith (1981). A few examples from shale formations are also presented, in which a horizontal well was fractured using a multi-stage fracturing technique. The analyzed data clearly shows the opening and dilation of the natural fractures.
Fracture and hydraulic fracture initiation, propagation and coalescence in shale
2017
Even though hydraulic fracturing has been in use for more than six decades to extract oil and natural gas, the fundamental mechanism to initiate and propagate these fractures remains unclear. Moreover, it is unknown how the propagating fracture interacts with other fractures in the Earth. The objective of this research is to gain a fundamental understanding of the hydraulic fracturing process in shales through controlled laboratory experiments where the underlying mechanisms behind the fracture initiation, -propagation, and -coalescence are visually captured and analyzed. Once these fundamental processes are properly understood, methods that allow one to produce desired fracture geometries can be developed. Two different shales were investigated: the organic-rich Vaca Muerta shale from the Neuquen Basin, Argentina and the clay-rich Opalinus shale from Mont Terri, Switzerland, which were shown to vary in mineralogy and mechanical properties. Specimen preparation techniques were devel...
Hydraulic fracturing: a review of theory and field experience
2015
This report summarises the current state-of-the-art knowledge of the hydraulic fracturing process used by the shale gas/oil industry using open peer-reviewed literature and from government commissioned research reports. This report has been written to make statements on our knowledge of the following questions: • How do hydrofractures form? • How far do hydrofractures extend during stimulation? • What dictates where hydrofractures propagate? • How do hydrofractures interact with the existing fracture network? • Can the size and distribution of hydrofractures be controlled? Gaps in our knowledge have been highlighted, with the largest of these resulting from differences between North American and European shale rocks.
Petroleum Science and Technology, 2010
Hydraulic fracturing is a key technology for the development of unconventional resources such as shale gas. Due to the existence of numerous bedding planes, shale reservoirs can be considered typical anisotropic materials. In anisotropic shale reservoirs, the complex hydraulic fracture network (HFN) formed by the interaction of hydraulic fracture (HF) and bedding plane (BP) is the key to fracturing treatment. In this paper, considering the anisotropic angle, stress state and injection rate, a series of hydraulic fracturing experiments were conducted to investigate the effect of anisotropic characteristics of shale reservoirs on HFN formation. The results showed that the breakdown pressure increased first and then decreased when the anisotropic angle changed at 0 •-90 • , while the circumferential displacement had the opposite trend with a small difference. When θ = 0 • , fracturing efficiency of shale specimens was much higher than that under other operating conditions. When θ ≤ 15 • , the bedding-plane mode is ubiquitous in all shale reservoirs. While θ ranged from 30 •-45 • , a comprehensive propagation pattern of bedding-plane and crossing is presented. When θ ≥ 60 • , the HFN pattern changes from comprehensive mode to crossing mode. The propagation pattern obtained from physical experiments were verified by theoretical analysis. The closure proportion of the circumferential displacement was the highest when the propagation pattern was the bedding-plane mode (θ ≤ 15 •), following by crossing. The closure proportion was minimum only when the bedding-plane and crossing mode were simultaneously presented in the HFN. The results can provide some basic data for the design in hydraulic fracturing of tight oil/gas reservoirs.
Rock Mechanics and Rock Engineering, 2013
Due to the low permeability of many shale reservoirs, multi-stage hydraulic fracturing in horizontal wells is used to increase the productive, stimulated reservoir volume. However, each created hydraulic fracture alters the stress field around it, and subsequent fractures are affected by the stress field from previous fractures. The results of a numerical evaluation of the effect of stress field changes (stress shadowing), as a function of natural fracture and geomechanical properties, are presented, including a detailed evaluation of natural fracture shear failure (and, by analogy, the generated microseismicity) due to a created hydraulic fracture. The numerical simulations were performed using continuum and discrete element modeling approaches in both mechanical-only and fully coupled, hydro-mechanical modes. The results show the critical impacts that the stress field changes from a created hydraulic fracture have on the shear of the natural fracture system, which in-turn, significantly affects the success of the hydraulic fracture stimulation. Furthermore, the results provide important insight into: the role of completion design (stage spacing) and operational parameters (rate, viscosity, etc.) on the possibility of enhancing the stimulation of the natural fracture network ('complexity'); the mechanisms that generate the microseismicity that occurs during a hydraulic fracture stimulation; and the interpretation of the generated microseismicity in relation to the volume of stimulated reservoir formation.