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Previous publications discussing the shallower portions of the Eagle Ford shale have demonstrated the engineering worth of combining the results of multiple fracture diagnostics, such as microdeformation and downhole microseismic. This paper extends previous work by incorporating results from a surface microseismic mapping study. Moment Tensor Microseismic Imaging™ (MTMI™) was performed to help provide a better understanding of the nature of microseismic failure mechanisms associated with the hydraulic fracture process and its interaction with the natural rock fabric. The study region is within the Eagle Ford shale in an area where previous microseismic mapping has indicated that the magnitude of the overburden stress is less than the magnitude of one or both of the two principal horizontal stresses (Walser and Roadarmel 2012). The source mechanisms derived from the surface imaging were assessed for two very different groups of microseismic events also observed during downhole microseismic mapping. Debate continues regarding the technical, practical, and fiscal value of understanding source mechanisms associated with microseismic activity (Baig and Urbancic 2010; Warpinski et al. 2010; Warpinski 2014;). This work demonstrates one situation where MTMI provided a deeper understanding of the fundamental geomechanical mechanisms occurring during hydraulic fracturing and highlights that, when examining the seismicity generated by a hydraulic fracture, one should always consider the fabric of the rock within which that stimulation occurred. This case study relates to a horizontal stimulation where monitoring observed evidence of interaction between the hydraulic fracture and several subvertical or subhorizontal pre-stressed natural features. This paper discusses the value of source mechanism information provided by MTMI and how it can be used with other fracture mapping technologies to help impact future exploration and production decisions.
A recently published analytic technique for computing locations of microseismic events jointly with velocities of homogeneous isotropic models is extended to surface microseismic monitoring and transverse isotropy with a tilted symmetry axis (TTI). The analysis of traveltimes of the direct P-, SV-, and SHwaves, conducted under the assumptions of homogeneity and weak anisotropy, reveals that the SVwave data acquired in modern wide-azimuth surface microseismic surveys yield uniquely solvable joint inverse problems for an arbitrary symmetry-axis tilt, whereas the tilts should be close to 90 ? from the vertical for the P-waves propagating in anelliptically anisotropic media and strictly equal to 90° for the SH-waves to maintain the uniqueness of the joint inversion. These theoretical findings, confirmed on raytracing synthetic, are applied to a field microseismic data set. The P-waves excited by microseismic events are found to exhibit significantly flatter moveouts and better focused stacks when located in a constructed effective TTI model as compared to those located in a horizontally layered isotropic model provided as a part of conventional microseismic service.
Hydraulic fracturing, routinely conducted to produce oil and gas from unconventional reservoirs, is often complemented by microseismic monitoring that helps delineate the created fracture networks and estimate the stimulated reservoir volume. Since its estimation primarily relies on hypocenters of microseismic events triggered in the course of a well treatment, it also requires a velocity model for computing those hypocenters. When building such a model, a geophysicist, typically aiming to account for the velocity heterogeneity and anisotropy, would either fix a model based on the available sonic logs and active-source data prior to locating the microseismicity (e.g., Pei et al., 2009) or construct a model simultaneously with locating the recorded microseismic events (Grechka and Yaskevich, 2014). This joint velocity-model building/event-location approach, applicable in the absence of sonic logs and active-source data, relies on the understanding of which velocityand anisotropy-related parameters are uniquely constrained in a given data-acquisition geometry.
Abstract The geometry of hydraulically-induced fracture systems is difficult to characterize. Microseismic monitoring is the only far-field measurement available to date that possesses the required granularity to determine how, when, and why, hydraulically-induced fracture systems propagate within the reservoir (and sometimes the surrounding formations). Correlation of production history with use of microseismic monitoring has often been positive. While operators acknowledge that there are interesting and valuable observations made during the interpretation of microseismic data, those who have previously acquired only a few microseismic datasets during their hydraulically fractured well completions face the challenge of justifying incremental value from acquiring additional microseismic data. Addressing the myths, misconceptions, realities, and opportunities of microseismic interpretation is then necessary to provide continuously improving answers to questions such as fluid and proppant selection, treatment design, completion design, well spacing, that directly affect drilling and completion costs in the effort of operators to optimize completion and stimulation designs. Understanding, proving and improving the value of microseismic measurements during fracturing treatments takes an increased importance, as in today's environment it has become more difficult to justify the capital investments required for microseismic monitoring projects. Introduction Microseismic monitoring is the foundation for unconventional hydraulic fracture diagnosis and hydraulic fracture calibration and is also commonly used in many areas such as geologic hazard monitoring, CO2 sequestration (Duncan and Eisner, 2010; Maxwell et al., 2010; Eisner et al., 2010) and EOR monitoring. Characterizing the geometry of hydraulically-induced fracture systems is a complex challenge and Microseismic monitoring is often complemented with other diagnostic methods to improve the accuracy of the results.
Anokhina, E.. (Immanuel Kant Baltic Federal University) | Zhegalina, L.. (Immanuel Kant Baltic Federal University) | Erokhin, G.. (Immanuel Kant Baltic Federal University) | Demidova, E.. (Immanuel Kant Baltic Federal University) | Strokov, V.. (Immanuel Kant Baltic Federal University) | Kozlov, M.. (Immanuel Kant Baltic Federal University)
Abstract The work purpose - application of microseismic monitoring in the process of technological actions. They are directed to intensification of hydrocarbon production, by identifying fracturing zones to control the fracturing, identifying zones of emission activity in the reservoir when injecting liquid in injection wells. A feature of this technology is the possibility of determining fracture zones using surface observation antennas, without observation wells. This distinguishes it from traditional well monitoring technologies. Also, this significantly reduces the cost of work, since there is no need to stop the wells at the time of monitoring and additionally bear the costs of lowering special equipment. This technology, in addition, has a high resolution mapping.
abstract Microseismic monitoring (MSM) of hydraulic fracture treatments is routine in North America and has added significantly to our understanding of fracture growth. The interpretation of microseismic images is advancing steadily, extracting more information from event patterns, temporal evolution, and acoustic waveforms. The increasing amount of information from MSM provides significant opportunities to improve stimulation designs, completion strategies, and field development. However, the applications of microseismic interpretations are many times ill-defined, overlooked, or not applied properly. Numerous applications of microseismic measurements have been documented in technical publications, typically in the form of case histories focused on specific applications. The industry has lacked a compilation and comprehensive discussion of microseismic applications. This paper presents a practical guide for the engineering application of microseismic interpretations, documenting reliable application workflows while highlighting the consequences of misapplication of microseismic interpretations. The application of MSM starts with a reliable interpretation of fracture geometry and complexity, but the real value is in the application of the interpretation. This paper divides microseismic applications into three categories, real-time, completion strategies & stimulation design, and field development. The MSM interpretation requirements for each category are documented and a comprehensive guide to properly applying these interpretations is presented. Applications issues such as determining the "effective" fracture surface area, the relationship between microseismic behavior and well performance, and fracture model calibration are addressed. There is a growing interest in advanced processing such as moment tensor inversion (MTI) and b-values to determine focal mechanisms, source parameters, and failure mechanisms associated with the microseismic events. However, the engineering application of these interpretations is not well understood. This paper includes a discussion of the applications of advanced processing results, emphasizing how the limitations and uncertainties of the processing affect the subsequent applications.