The complex fracture network or stimulated reservoir volume (SRV) can be induced by hydraulic fracturing of the unconventional reservoirs. The SRV dimension is one of the main drivers in a horizontal well performance after the hydraulic fracturing operation. It is of great importance to simulate the SRV dimensions to identify the optimum hydraulic fracturing treatment parameters. In this research, a new analytical model is proposed to accurately simulate the SRV dimension created from hydraulically fractured horizontal wells in unconventional reservoirs. More specifically, a SRV dimensional model is developed to simulate SRV dimensions using effective stresses, injected slurry volume and other reservoir and pumping data during the generation of the hydraulic fracture network. The SRV dimensional model is calibrated using microseismic data from 6 stages of a hydraulic fracturing job in a horizontal well penetrating the Glauconite formation in Hoadley field, Alberta, Canada. The calibrated SRV dimensional model can serve as an optimal fracture spacing estimator for future hydraulic fracture job designs. The average simulated SRV width is smaller than the average fracture port spacing and therefore for this study it is suggested to have the fracture port spacing tighter and equal with the simulated SRV width for optimum production.
Upfront predictions of hydraulic fracturing and gas production of potential shale gas targets in Europe are important as often large potential resources are deduced without detailed knowledge on the potential for successful stimulation. Such predictions are challenging as they need to be based on limited available data, i.e. without well tests or proper case studies. In this study, a geological model was constructed for a representative area in the South of the Netherlands (Noord-Brabant province) where a potential shale gas target (the Posidonia Shale Formation) is present in the subsurface. Petrophysical analysis of rock properties and geomechanical analysis of the stress field are performed. The sensitivity of hydraulic fracturing to rock properties, stress state and treatment schedules was studied using a commercially available hydraulic fracturing simulator. A systematic series of simulations was performed for a range of input parameters to address geological uncertainty and optimum stimulation treatment. The results show that uncertainty in leakoff coefficient and minimum horizontal stress are most important in predicting fracture dimensions and conductivity. Minor upward growth of fractures is observed for all scenarios. Analysis of Coulomb stress changes due to hydraulic fracturing shows that opening of fractures alone is unlikely to cause fault reactivation.
Shale gas has become an increasingly important source of natural gas (CH4) in the United States over the last decade. Due to its unconventional characteristics, injecting carbondioxide (CO2) to enhance shale gas recovery (ESGR) is a potentially feasible method to increase gas-yield while both affording a sink for CO2 and in reducing the potential for induced seismicity. This study examines CO2 -ESGR to better understand its feasibility and effectiveness. We explore the roles of important coupled phenomena activated during gas substitution especially vigorous feedbacks between sorptive behavior and permeability evolution. Permeability and porosity evolution models developed for sorptive fractured coal are adapted to the component characteristics of gas shales. These adapted models are used to probe the optimization of CO2 -ESGR for injection of CO2 at overpressures of 0MPa, 4MPa and 8MPa to investigate magnitudes of elevated CH4 production, CO2 storage rate and capacity, and of CO2 early-breakthrough and permeability evolution in the reservoir. For the injection pressures selected, CH4 production was enhanced by 2.3%, 14.3%, 28.5%, respectively, over the case where CO2 is not injected. Distinctly different evolutions are noted for permeability in both fractures and matrix due to different dominating mechanisms. Fracture permeability increased by ~ ⅓ for the injection scenarios due to the dominant influence of CH4 de-sorption over CO2 sorption. CO2 sequestration capacity was only of the order of 104 m3 when supercritical for a net recovery of CO2 of 108 m3.
Recent advances in high power plasma torch technology provide an apparatus to replace the conventional perforation methods in oil and gas wells. High power plasma torches are capable of cutting and removing rocks textures efficiently and they might be considered as one of the appropriate substitutions for current shaped charge perforation methods. According to its advantages the conventional shaped charge methods that one the important one is increasing permeability considerably and no need to have costly re-perforation operations to decreasing new formation damage named by perforation skin. Plasma torch perforation is gone along with heat flux generation. As the temperature increases during plasma torch operation, thermal energy accumulates the matrix expansion. This expansion generate thermal stresses induce the rock texture. Furthermore, thermal stresses exceeds the rock strength, thermal fractures will form in texture that mainly depend on rock thermal properties, pore size distribution, applied thermal stresses and confining and pore pressures. In this paper, the results of experimental studies on implementation of high power plasma torch in perforation and fracture initiation in oil and gas wells is presented. Also, numerically analyzing of generating these thermal fractures during plasma torch perforation will facilitate hydraulic fracturing operation.
Hydraulic fracturing technique has been widely applied in the enhanced geothermal systems, to increase injection rates for geologic sequestration of CO2, and most importantly for the stimulations of oil and gas reservoirs, especially the unconventional shale reservoirs. One of the key points for the success of hydraulic fracturing operations is to accurately estimate the redistribution of pore pressure and stresses around the induced fracture and predict the reactivations of pre-existing faults. The fracture extension as well as pore pressure and stress regime around it are affected by: poro- and thermoelastic phenomena as well as by fracture opening under the combined action of applied pressure and in-situ stress. A couple of numerical studies have been done for the on this for the purpose of analyzing the potential for fault reactivation resulting from pressurization of the hydraulic fracture. In this work, a comprehensive analytical model is constructed to estimate the stress and pore pressure distribution around an injection induced fracture from a single well in an infinite reservoir. The model allows the leak-off distribution in the formation to be three-dimensional with the pressure transient moving ellipsoidcally outward into the reservoir with respect to the fracture surface. The pore pressure and the stress changes in three dimensions at any point around the fracture caused by thermo- and poroelasticity and fracture compression are investigated. Then, the problem of constant water injection into a hydraulic fracture in Barnett shale is presented. In particular, with Mohr-Coulomb failure criterion, we calculate the fault reactivation potential around the fracture. This study is of interest in interpretation of micro-seismicity in hydraulic fracturing and in assessing permeability variation around a stimulation zone, as well as in estimation of the fracture spacing during hydraulic fracturing operations.
Enhancing formation permeability through hydraulic fracturing (HF) has become a proven tool for hydrocarbon extraction in shale (i.e., a resource rock formation) as well as geothermal heat extraction from hot, dry rock reservoirs. Permeability in the nanodarcy range is possible in many such unconventional oil and gas reservoirs, thus requiring production to greatly depend on the existence of natural fractures and the additional surface area generated by hydraulic fracturing. Mapping and characterizing the structure of a hydraulic fracture network can be performed using acoustic emission analysis techniques. Many techniques exist to obtain an estimated stimulated reservoir volume (SRV), which is used as a correlation metric for expected well performance. Most of these techniques use the discrete acoustic emission events as boundary points and determine the volume of rock inside the three-dimensional cloud of data that was acquired. While some of these methods for determining rock volumes affected throughout the fracturing process are sophisticated, understanding of the cumulative fracture opening volume from acoustic emission data is not well understood. Laboratory hydraulic fracturing tests were performed while monitoring acoustic emissions continuously. Sample sizes were approximately 15×15×25 cm3. Granite was used as the reservoir material due to the high brittleness, very low permeability, and relative homogeneity. Acoustic emission data recorded throughout the fracturing process was analyzed for three-dimensional event source locations, source mechanisms, orientations and directions of crack movement, and volumetric deformations. A cumulative volumetric deformation was calculated for a specific area near the openhole wellbore where fracture initiation occurred. This volumetric deformation was then compared to micron scale CT scan data for the same region. The fracturing pattern and the geometrical properties of fracturing (e.g., volume, fracture width, etc.) can be measured and analyzed from the 3D CT images. The resolution of the micro-CT images is sufficient to resolve most tiny fractures. By direct observation through micron CT imaging, the acoustic emission data is compared. The consistence of volumetric contributions of these two sets of data is investigated.
A new approach to upscaling and modeling of geomechanical properties using clusters has been set-up for Vaca Muerta Formation in the Neuquén Basin of Argentina. Using wells with core and cross-dipole logging tools, a core calibrated anisotropic model of the formation has been established. Clusters were determined from a logging suite comprising only gamma ray, compressional slowness, and bulk density in a key exploration well, and this cluster group was applied to several more wells in the study area. Using microseismic data obtained from three of the wells in the study area with two fracturing stages each, the vertical extent of microseismic events was determined, and the clusters obtained through our analysis have been upscaled over this interval using Backus averaging. All four upscaled wells show similar results by cluster for elastic stiffness coefficients and Young’s moduli, with a very tight range of values. Poisson’s ratio is more variable and a vague trend with the clusters is noticed. When compared to the core data, similar trends are observed in the stiffness coefficients and Young’s moduli. These clusters have been used as geomechanical facies to populate a 3D MEM which can be used to couple the petrophysical model for the study area, regional stress model, regional structure, and natural fracture network in order to combine the fully coupled geomechanics and flow effects in hydraulic fracturing treatments. The method we have developed allows for anisotropic properties to be applied over a wide area with limited available logging data.
Elastic and plastic mechanical properties of liquids-rich shale rocks play a critical role in well placement and stimulation. In this study, elastic, plastic, and failure behavior of the Lower Jurassic Nordegg Member from various wells in the Western Canada Sedimentary Basin is investigated with laboratory triaxial compression tests. The triaxial compression tests show a wide range of elastic parameters, e.g. Young’s moduli ranging from <10 GPa to >30 GPa and Poisson’s ratios from <0.15 to >0.35. Mechanical anisotropy is also observed with vertically-oriented samples (normal to bedding) generally having lower compressive strength and Young’s modulus than horizontally-oriented samples (parallel to bedding). The characteristics of plastic deformation, brittle and/or ductile behavior, and residual strengths are also investigated. The variability in measured mechanical properties suggests the highly variable lithologies and fabrics in these samples. Efforts are made to delineate possible correlations between the rock mechanical properties, mineralogy, fabric, porosity, and pore-throat size distribution. The study also discusses the implications of the variable elastic and plastic mechanical properties on determining optimal placement of horizontal wells in the Nordegg Member, designing for multistage-fracture stimulation and selecting appropriate proppant. Proppant embedment and fracture conductivity are discussed using laboratory data and analytical and numerical analyses.
Ability to induce complex, highly connected fracture networks, that can remain open during production, is the key to unlock permeability challenged shale gas plays. Within the time and pressure scale of hydraulic fracturing operations, it is difficult to create fracture complexity in ductile shales. However, when subjected to a high rate/pulse loading, rock might exhibit a brittle to ductile transition and a complex fracture network might be created. Along these lines, the concept of pulsed fracturing, that customizes the pressure-time behavior of a pulse source to create multiple fractures, is introduced. In this paper, an integrated 3D model that quantifies fracture initiation, growth, and coalescence due to initial and post-peak pulse loading is presented. The simulation involves a numerical algorithm that couples tensile/shear/compactive failure algorithms with dynamic fracture propagation and pore fluid pressure. Geomechanical modeling approach makes it possible to optimize pulsed fracturing for different shale plays. After constitutive model description and presentation of key aspects of the model, the model is employed to a reservoir dataset to evaluate pulsed fracturing as an alternative fracturing technique. The results show that, if designed accurately, pulsed fracturing could help trigger a ductile to brittle transition and can generate complex fracture networks.
Hydrocarbon extraction from unconventional oil and gas reservoirs requires more accurate ways to describe fracture processes in shale. Fracture initiation, propagation and coalescence has been studied in many rock-like materials [1,2] and natural rocks [1,2,3] . However, shale is typically heterogeneous and anisotropic with naturally formed bedding planes. Natural bedding planes can be weak zones where fractures can initiate and propagate along [1, 2, 3]. A series of unconfined compression tests were conducted on Opalinus clay shale with two pre-existing flaws and various bedding plane orientations (0, 30, 60, and 90 degrees with respect to the horizontal). High speed and high resolution imagery were use to capture fracture initiation, propagation and coalescence between the flaw pairs. Distinct coalescence and cracking patterns were observed when compared to previously tested rocks. As the bedding angle increased, fractures initiating at the flaw tips tended to propagate more frequently along the bedding planes. Coalescence of cracks between flaws trended from direct-combined (tensile and shear cracks) to indirect as the bedding plane angle increased. Tensile crack initiation and coalescence stresses showed a characteristic U-shape profile with a minimum at 60 degree bedding plane orientation and a maximum at 0 degree bedding plane orientation.