Pitfalls locating microseismic events from borehole measurements — Practical observations from field applications

2013 ◽  
Vol 1 (2) ◽  
pp. A11-A17 ◽  
Author(s):  
Carlos Cabarcas
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Microseismic Monitoring ◽  
Reservoir Stimulation ◽  
Velocity Models ◽  
Unconventional Resources ◽  
Geophysical Techniques ◽  
Microseismic Events ◽  
The Impact

Borehole microseismic monitoring of hydraulic fracturing is among the best tools for reservoir stimulation evaluation. After decades of research and execution, the technique has gained a well-deserved place within the engineering toolbox. Moreover, in recent years, its popularity has increased exponentially, together with the development of unconventional resources. However, while involved with a significant number of borehole microseismic monitoring campaigns, I noticed that it is a common practice to overlook fundamental principles during the location of microseismic events. This may lead to potentially erroneous hydraulic fracturing assessments. Examples of microseismic results qualitatively illustrate this assertion showing poor recording, velocity models, processing constraints, and display. They also underscore the interpreter’s role in ensuring the most reasonable outcome from a microseismic hydraulic fracture evaluation. In this respect, any conclusion derived from a microseismic experiment should be fully supported by a thorough understanding of the impact that multiple acquisition and processing assumptions have on the interpretation, as is the case for all other geophysical techniques. Ultimately, my intent is to raise awareness of some common pitfalls while also providing recommendations to increase the value of a microseismic monitoring exercise.

Results of the downhole microseismic monitoring at a pilot hydraulic fracturing site in Poland — Part 1: Event location and stimulation performance

2018 ◽  
Vol 6 (3) ◽  
pp. SH39-SH48 ◽  
Author(s):  
Wojciech Gajek ◽  
Jacek Trojanowski ◽  
Michał Malinowski ◽  
Marek Jarosiński ◽  
Marko Riedel
Keyword(s):  
Hydraulic Fracturing ◽  
Seismic Anisotropy ◽  
Transverse Isotropy ◽  
Velocity Model ◽  
Microseismic Monitoring ◽  
Baltic Basin ◽  
Hydraulic Stimulation ◽  
Lower Paleozoic ◽  
Event Location ◽  
Microseismic Events

A precise velocity model is necessary to obtain reliable locations of microseismic events, which provide information about the effectiveness of the hydraulic stimulation. Seismic anisotropy plays an important role in microseismic event location by imposing the dependency between wave velocities and its propagation direction. Building an anisotropic velocity model that accounts for that effect allows for more accurate location of microseismic events. We have used downhole microseismic records from a pilot hydraulic fracturing experiment in Lower-Paleozoic shale gas play in the Baltic Basin, Northern Poland, to obtain accurate microseismic events locations. We have developed a workflow for a vertical transverse isotropy velocity model construction when facing a challenging absence of horizontally polarized S-waves in perforation shot data, which carry information about Thomsen’s [Formula: see text] parameter and provide valuable constraints for locating microseismic events. We extract effective [Formula: see text], [Formula: see text] and [Formula: see text], [Formula: see text] for each layer from the P- and SV-wave arrivals of perforation shots, whereas the unresolved [Formula: see text] is retrieved afterward from the SH-SV-wave delay time of selected microseismic events. An inverted velocity model provides more reliable location of microseismic events, which then becomes an essential input for evaluating the hydraulic stimulation job effectiveness in the geomechanical context. We evaluate the influence of the preexisting fracture sets and obliquity between the borehole trajectory and principal horizontal stress direction on the hydraulic treatment performance. The fracturing fluid migrates to previously fractured zones, while the growth of the microseismic volume in consecutive stages is caused by increased penetration of the above-lying lithologic formations.

Microseismicity-constrained discrete fracture network models for stimulated reservoir simulation

Geophysics ◽  
2013 ◽  
Vol 78 (1) ◽  
pp. B37-B47 ◽  
Author(s):  
Sherilyn Williams-Stroud ◽  
Chet Ozgen ◽  
Randall L. Billingsley
Keyword(s):  
Hydraulic Fracture ◽  
Fracture Network ◽  
Discrete Fracture Network ◽  
Three Dimensions ◽  
Fracture Flow ◽  
Signal To Noise ◽  
Discrete Fracture ◽  
Microseismic Events ◽  
The Impact ◽  
Dfn Model

The effectiveness of hydraulic fracture stimulation in low-permeability reservoirs was evaluated by mapping microseismic events related to rock fracturing. The geometry of stage by stage event point sets were used to infer fracture orientation, particularly in the case where events line up along an azimuth, or have a planar distribution in three dimensions. Locations of microseismic events may have a higher degree of uncertainty when there is a low signal-to-noise ratio (either due to low magnitude or to propagation effects). Low signal-to-noise events are not as accurately located in the reservoir, or may fall below the detectability limit, so that the extent of fracture stimulated reservoir may be underestimated. In the Bakken Formation of the Williston Basin, we combined geologic analysis with process-based and stochastic fracture modeling to build multiple possible discrete fracture network (DFN) model realizations. We then integrated the geologic model with production data and numerical simulation to evaluate the impact on estimated ultimate recovery (EUR). We tested assumptions used to create the DFN model to determine their impact on dynamic calibration of the simulation model, and their impact on predictions of EUR. Comparison of simulation results, using fracture flow properties generated from two different calibrated DFN scenarios, showed a 16% difference in amount of oil ultimately produced from the well. The amount of produced water was strongly impacted by the geometry of the DFN model. The character of the DFN significantly impacts the relative amounts of fluids produced. Monitoring water cut with production can validate the appropriate DFN scenario, and provide critical information for the optimal method for well production. The results indicated that simulation of enhanced permeability using induced microseismicity to constrain a fracture flow property model is an effective way to evaluate the performance of reservoirs stimulated by hydraulic fracture treatments.

Applications of Geomechanics to Hydraulic Fracturing - Case Studies from Coal Stimulations

2015 ◽  
Author(s):  
Vibhas J. Pandey
Keyword(s):  
Mechanical Property ◽  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
History Matching ◽  
Reservoir Rock ◽  
Eastern Australia ◽  
Input Parameters ◽  
Practical Standpoint ◽  
The Impact

Abstract Modern hydraulic fracture treatments rely heavily on the implementation of formation property details such as in-situ stresses and rock mechanical properties, in order to optimize stimulation designs for specific reservoir targets. Log derived strain and strength calibrated in-situ properties provide critical description of stress variations in different lithologies and at varying depths. From a practical standpoint however, most of the hydraulic fracture simulators that are used for fracturing treatment design purposes today can accommodate only a limited portion of a geologic-based rock mechanical property characterization which targets optimal data integration thus resulting in complexity. By using examples from hydraulic fracture stimulations of coals in a complex but well characterized stress environment (Surat Basin, Eastern Australia) we distil out the reservoir rock related input parameters that are determinants of hydraulic fracture designs and identify those that are not immediately used. In order to understand the impact on improving future fracture stimulation designs, the authors present workflows such as pressure history matching of fracture stimulation treatments and the calibration process of key rock mechanical parameters such as Poisson's ratio, Young's modulus, and fracture toughness. The authors also present examples to discuss synergies, discrepancies and gaps that currently exist between ‘geologic’ geomechanical concepts (i.e. variations in the geometry and magnitude of stress tensors and their interaction with pre-existing anisotropies) in contrast to the geomechanical descriptions and concepts that are used and implemented in hydraulic fracturing stimulations. In the absence of a unifying hydraulic fracture design that honors well established geologic complexity, various scenarios that allow assessing the criticality, usefulness and weighting of geologic/mechanical property input parameters that reflect critical reservoir complexity, whilst maintaining applicability to hydraulic fracturing theory, are presented in the paper. Ultimately it remains paramount to constrain as many critical variables as realistically and uniquely possible. Significant emphasis is placed on reservoir-specific pre-job data acquisition and post-job analysis. The approach presented in this paper can be used to refine hydraulic fracture treatment designs in similar complex reservoirs worldwide.

Microseismic Monitoring of Hydraulic Fracturing – Data Interpretation Methodology with an Example from Pomerania

2017 ◽  
Author(s):  
Michał Antoszkiewicz ◽  
Mateusz Kmieć ◽  
Paweł Szewczuk ◽  
Marek Szkodo ◽  
Robert Jankowski
Keyword(s):  
Hydraulic Fracturing ◽  
Signal To Noise Ratio ◽  
Velocity Model ◽  
Data Interpretation ◽  
Microseismic Monitoring ◽  
Grid Search ◽  
Moment Tensors ◽  
Spatial Image ◽  
Microseismic Events ◽  
Breakage Mechanism

Microseismic monitoring is a method for localizing fractures induced by hydraulic fracturing in search for shale gas. The aim of this paper is to conduct the data interpretation of the microseismic monitoring based on the results from Pom-erania region of Poland. The data has been collected from an array of geophones deployed on the surface. Ground vibrations have been recorded and analyzed for fracture location, magnitude and breakage mechanism. A velocity model of underlying formations has been used for successful microseismic monitoring. The model has been further tuned with signal from perfora-tion shots of known location. Imaging of events has been done using software MicSeis, which utilizes diffraction stacking of waveforms from multiple stations to image microseismic events with low signal-to-noise ratio. The imaging of microseismic events in MicSeis uses a grid search over all possible origin times and locations in the selected rock volume. The seismic moment tensors are automatically determined from the amplitudes from the grid search procedure and are used to model po-larities of events which then enhance constructive interference. Function characterizing a maximum stack per time sample have been calculated over whole volume and analyzed using the STA/LTA algorithm. Once the event has been detected in time, location has been determined through analysis of the 3D spatial image function. The procedure has been used to detect five events during hydraulic fracturing in Pomerania.

Evolution of a block cave from time-lapse passive source body-wave traveltime tomography

Geophysics ◽  
2015 ◽  
Vol 80 (2) ◽  
pp. WA85-WA97 ◽  
Author(s):  
Jean-Philippe Mercier ◽  
Willem de Beer ◽  
Jean-Pascal Mercier ◽  
Simon Morris
Keyword(s):  
Rock Mass ◽  
Velocity Distribution ◽  
Body Wave ◽  
Time Lapse ◽  
Microseismic Monitoring ◽  
Monitoring Systems ◽  
Simultaneous Estimation ◽  
Velocity Models ◽  
Microseismic Events ◽  
Microseismic Event

Most underground mines are equipped with microseismic monitoring systems that allow the detection, location, and characterization of microseismic events. Microseismic events can be exploited to understand the rock mass response to mining. However, seismicity provides information only for regions that are seismically active. Although some information on nonseismically active regions can be obtained from point measurements and numerical modeling, these methods suffer from limitations of their own. Passive source traveltime body-wave tomography (passive source tomography [PST]) uses information readily collected by microseismic monitoring systems, namely, the P- and/or S-wave traveltimes and microseismic event hypocenter locations. This technique allowes the simultaneous estimation of the velocity distribution between sensors and microseismic events and the correction of microseismic event hypocenter locations. In this paper, we present an application of time-lapse PST to the Northparkes Mines E26 Lift 2 block cave showing that PST can be used to obtain information on evolution and distribution of seismic velocities, leading to a better understanding of stress distribution and redistribution and of rock mass behavior during the development and production phases. In particular, we found that (1) the magnitude of the velocity perturbation varied through time and appeared to be strongly correlated with the intensity of microseismic activity, the mining rate, and the nature of the mining activity, (2) the velocity models provided information that allowed for the inference of the cave geometry and its evolution through time, (3) the stress distributions inferred from the velocity model were not fully consistent with a widely accepted conceptual stress redistribution model, which may reflect the significant influence of rock mass inhomogeneities and the mining sequence, (4) seismicity was found in regions in which velocity was higher and lower than the background velocity, and (5) there was no obvious correlation between geology and velocity distribution and evolution.

Integration of Dynamic Microseismic Data With a True 3D Modeling of Hydraulic-Fracture Propagation in the Vaca Muerta Shale

SPE Journal ◽  
2017 ◽  
Vol 22 (06) ◽  
pp. 1714-1738 ◽  
Author(s):  
Mahdi Haddad ◽  
Jing Du ◽  
Sandrine Vidal-Gilbert
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
Natural Fracture ◽  
Zone Model ◽  
Fluid Viscosity ◽  
Fracture Intersection ◽  
Vaca Muerta ◽  
Hydraulic Fracture Propagation ◽  
Microseismic Events

Summary Microseismic mapping during the hydraulic-fracturing processes in the Vaca Muerta (VM) Shale in Argentina shows a group of microseismic events occurring at shallower depth and at later injection time, and they clearly deviate from the growing planar hydraulic fracture. This spatial and temporal behavior of these shallow microseismic events incurs some questions regarding the nature of these events and their connectivity to the hydraulic fracture. To answer these questions, in this article, we investigate these phenomena by use of a true 3D fracture-propagation-modeling tool along with statistical analysis on the properties of microseismic events. First, we propose a novel technique in Abaqus incorporating fracture intersections in true 3D hydraulic-fracture-propagation simulations by use of a pore-pressure cohesive zone model (CZM), which is validated by comparing our numerical results with the Khristianovic-Geertsma-de Klerk (KGD) solution (Khristianovic and Zheltov 1955; Geertsma and de Klerk 1969). The simulations fully couple slot flow in the fracture with poroelasticity in the matrix and continuum-based leakoff on the fracture walls, and honor the fracture-tip effects in quasibrittle shales. By use of this model, we quantify vertical-natural-fracture activation and fluid infiltration depending on reservoir depth, fracturing-fluid viscosity, mechanical properties of the natural-fracture cohesive layer, natural-fracture conductivity, and horizontal stress contrast. The modeling results demonstrate this natural-fracture activation in coincidence with the hydraulic-fracture-growth complexities at the intersection, such as height throttling, sharp aperture reduction after the intersection, and multibranching at various heights and directions. Finally, we investigate the hydraulic-fracture intersection with a natural fracture in the multilayer VM Shale. We infer the natural-fracture location and orientation from the microseismic-events map and formation microimager log in a nearby vertical well, respectively. We integrate the other field information such as mechanical, geological, and operational data to provide a realistic hydraulic-fracturing simulation in the presence of a natural fracture. Our 3D fracturing simulations equipped with the new fracture-intersection model rigorously simulate the growth of a realistic hydraulic-connection path toward the natural fracture at shallower depths, which was in agreement with our microseismic observations.

scholarly journals Microseismic event detection in large heterogeneous velocity models using Bayesian multimodal nested sampling

2021 ◽  
Vol 2 ◽  
Author(s):  
Saptarshi Das ◽  
Michael P. Hobson ◽  
Farhan Feroz ◽  
Xi Chen ◽  
Suhas Phadke ◽  
...  
Keyword(s):  
Event Detection ◽  
Marginal Likelihood ◽  
Microseismic Monitoring ◽  
Origin Time ◽  
Nested Sampling ◽  
Velocity Models ◽  
Microseismic Events ◽  
Spatio Temporal ◽  
Microseismic Event ◽  
False Event

Abstract In passive seismic and microseismic monitoring, identifying and characterizing events in a strong noisy background is a challenging task. Most of the established methods for geophysical inversion are likely to yield many false event detections. The most advanced of these schemes require thousands of computationally demanding forward elastic-wave propagation simulations. Here we train and use an ensemble of Gaussian process surrogate meta-models, or proxy emulators, to accelerate the generation of accurate template seismograms from random microseismic event locations. In the presence of multiple microseismic events occurring at different spatial locations with arbitrary amplitude and origin time, and in the presence of noise, an inference algorithm needs to navigate an objective function or likelihood landscape of highly complex shape, perhaps with multiple modes and narrow curving degeneracies. This is a challenging computational task even for state-of-the-art Bayesian sampling algorithms. In this paper, we propose a novel method for detecting multiple microseismic events in a strong noise background using Bayesian inference, in particular, the Multimodal Nested Sampling (MultiNest) algorithm. The method not only provides the posterior samples for the 5D spatio-temporal-amplitude inference for the real microseismic events, by inverting the seismic traces in multiple surface receivers, but also computes the Bayesian evidence or the marginal likelihood that permits hypothesis testing for discriminating true vs. false event detection.

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