Fracturing unconventional formations to enhance productivity (original) (raw)
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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 of hydraulic fracturing processes in shale formations with complex geological settings
Journal of Petroleum Science and Engineering
The influence of geological structures on fracture propagation induced by hydraulic fracturing is studied. • Changes in the injection pressure and fracture permeability are studied as a function of time. • Fracture propagation is limited by geological structures softer than the surrounding rock. • The increase in the injection pressure is slightly higher when fracture propagation is limited by geological structures.
Formation damage simulation of a multi-fractured horizontal well in a tight gas/shale oil formation
Journal of Petroleum Exploration and Production Technology
Formation damage in drilling comes from drilling fluid invasion due to high differential pressure between a wellbore and the formation. This mechanism happens with fracture fluid invasion of multi-fractured horizontal wells in tight formations. Some multi-fractured wells show production rates and cumulative productions far lower than expected. Those damaged wells may sustain further impact such as well shutting due to unexpected events such as the COVID-19 outbreak and then experience a further reduction in cumulative production. This paper focuses on the root causes of formation damage of fractured wells and provides possible solutions to improve production. A simulation study was conducted using Computer Modelling Group software to simulate formation damage due to fracture fluid invasion and well shut-in. Simulation results revealed that the decrease in cumulative hydrocarbon production due to leak-off and shut-in of the simulated well could range from 20 to 41%, depending on diff...
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.
Geophysical Journal International, 2020
Hydraulic fracturing plays a vital role in the development of unconventional energy resources, such as shale gas/oil and enhanced geothermal systems to increase the permeability of tight rocks. In this study, we conducted hydraulic fracturing experiments in a laboratory using carbonate-rich outcrop samples of Eagle Ford shale from the United States. We used a thermosetting acrylic resin containing a fluorescent compound as a fracturing fluid. Immediately after fracturing, the liquid resin penetrated in the fractured blocks was hardened by applying heat. Then, the crack was viewed under UV irradiation, where the fluorescent resin allowed the induced fracture to be clearly observed, indicating the formation of simple, thin bi-wing planar fractures. We observed the detailed structure of the fractures from microscopy of thin cross-sections, and found that their complexity and width varied with the distance from the wellbore. This likely reflects the change in the stress state around the tip of the growing fracture. The interaction between fractures and constituent grains/other inclusions (e.g. organic substances) seemed to increase the complexity of the fractures, which may contribute to the efficient production of shale gas/oil via hydraulic fracturing. We first detected acoustic emission (AE) signals several seconds before the peak fluid pressure was observed, and the active region gradually migrated along the microscopically observed fracture with increasing magnitude. Immediately after the peak pressure was observed, the fluid pressure dropped suddenly (breakdown) with large seismic waves that were probably radiated by dynamic propagation of the fracture; thereafter, the AE activity stopped. We applied moment tensor inversion for the obtained AE events by carefully correcting the AE sensor characteristics. Almost all of the solutions corresponded to tensile events that had a crack plane along the maximum compression axis, as would be expected based on the conventional theory of hydraulic fracturing. Such domination of tensile events has not been reported in previous studies based on laboratory/in situ experiments, where shear events were often dominant. The extreme domination of the tensile events in the present study is possibly a result of the use of rock samples without any significant pre-existing cracks. Our experiments revealed the fracturing behaviour and accompanying seismic activities of very tight rocks in detail, which will be helpful to our understanding of fracturing behaviour in shale gas/oil resource production.
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.
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.
Sensitivity of fractured horizontal well productivity to reservoir properties in shale-gas plays
2013
This research presents an investigation of the sensitivity of fractured horizontal well performances to reservoir properties in ultra-tight, naturally fractured shale-gas reservoirs under depletion. The method of the research is analytical. Following a general review of the existing literature on well performances in unconventional tight reservoirs, the analytical trilinear flow model developed by Ozkan et al. (2011) is introduced. The original dimensionless trilinear flow solution in Laplace domain is converted to dimensional form to be used in productivity index calculations. The productivity of fractured horizontal wells in shale-gas plays is discussed in terms of transient productivity index defined by Araya and Ozkan (2002). For the purposes of this research, the stimulated reservoir volume (hydraulically fracturing the horizontal well in order to create pathways from the induced fractures towards the existing naturally fractured reservoir, creating either a complex network of fractures through hydraulic fracturing, or rejuvenating the existing healed fractures to create an effective stimulation zone around the well) assumption is implemented. This assumption, commonly used for shale-gas wells, limits the drainage of the well to the stimulated volume around the well and strongly influences the average pressure to be used in productivity computations. Derivation of the average pressure relationship for the dual-porosity (naturally fractured) stimulated reservoir volume is presented and the expression for the average pressure is combined with the transient trilinear flow solution to obtain a relation for the transient productivity index. As a means of investigating the iv sensitivity of productivity to a selected set of reservoir properties, the derivatives of the productivity index with respect to these properties are derived. The results of the research are presented in three forms: (i) productivity index versus time for the low, base, and high values of the selected property and the productivity index versus the change in property value at selected times, (ii) tornado charts indicating the sensitivity of the productivity index to the selected properties at different times, and (iii) change in productivity index (derivative of productivity index) with the variation of the selected properties. The results indicate that, unlike the common expectation, the productivity of the fractured horizontal wells in shale-gas plays is not very sensitive to the permeability of the natural fractures in the stimulated reservoir volume and/or the distance between hydraulic fractures. The permeability of the shale matrix and the density of the natural fractures in the stimulated reservoir volume, on the other hand, influence productivity by 600% and 300% respectively. The hydraulic fracture permeability and half-length appear to moderately influence productivity on a 5% to 20% range. These results should be useful to guide well completion in shale-gas plays, and the sensitivity analysis provided in this thesis should be useful for engineering analysis of projects. v
Effective and Sustainable Hydraulic Fracturing, 2013
A comprehensive geomechanical study was carried out to optimize stimulation for a fractured tight gas reservoir in the northwest Tarim Basin. Conventional gel fracturing and acidizing operations carried out in the field previously failed to yield the expected productivity. The objective of this study was to assess the effectiveness of slickwater or low-viscosity stimulation of natural fractures by shear slippage, creating a conductive, complex fracture network. This type of stimulation is proven to successfully exploit shale gas resources in many fields in the United States. © 2013 Gui et al.; licensee InTech. This is an open access article distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.