Simultaneous microseismic event localization and source mechanism determination

Geophysics ◽  
2015 ◽  
Vol 80 (1) ◽  
pp. KS1-KS9 ◽  
Author(s):  
Oksana Zhebel ◽  
Leo Eisner
Keyword(s):  
Oil And Gas ◽  
Signal To Noise Ratio ◽  
Moment Tensor ◽  
Microseismic Monitoring ◽  
Primary Objective ◽  
Gas Production ◽  
Source Mechanism ◽  
Seismic Events ◽  
Near Surface ◽  
Microseismic Event

Microseismic monitoring has become a tool of choice for the development and optimization of oil and gas production from unconventional reservoirs. The primary objective of (micro) seismic monitoring includes localization of (micro) seismic events and characterization of their source mechanisms. Most seismic events are of a nonexplosive nature, and thus, there are waveform (polarity) differences among receivers. Specifically, double-couple sources represented a challenge for migration-based localization techniques. We developed and applied a new migration-type location technique combined with source mechanism inversion that allowed for constructive interference of signal in seismic waveforms. The procedure included constructing image functions by stacking the amplitudes with compensated polarity changes. The compensation weights were calculated by using moment tensor inversion. This method did not require any picking of arrivals at individual receivers, but it required receivers to be distributed in multiple azimuths and offsets. This made the technique suitable for surface or near-surface monitoring, in which a low signal-to-noise ratio (S/N) can be overcome by stacking. Furthermore, the advantage of this technique was that in addition to the position in time and space, we also determined the source mechanism. We determined with numerical tests that the proposed technique can be used for detection and location of events with S/Ns as low as 0.05 at individual (prestacked) receivers. Furthermore, we found that other source mechanism parameters such as magnitude, volumetric, or shear components of the source mechanism were not suitable for the location. Finally, we applied the proposed technique to a microseismic event of moment magnitude [Formula: see text] induced during the hydraulic fracturing treatment of a gas shale reservoir in North America.

On the Feasibility of Using Underwater Acoustic Data Transmission for Subsea Equipment Monitoring

2017 ◽  
Author(s):  
Bessie A. Ribeiro ◽  
Viviane Rodrigues ◽  
Viviane Ferreira ◽  
Fabio C. Xavier ◽  
Theodoro A. Netto
Keyword(s):  
Data Transmission ◽  
Oil And Gas ◽  
Transmission Loss ◽  
Signal To Noise Ratio ◽  
Water Environment ◽  
Acoustic Propagation ◽  
Gas Production ◽  
Brazilian Coast ◽  
Propagation Channel ◽  
Oil And Gas Production

The present work uses the BELLHOP ray tracing model to simulate an acoustic propagation channel in a deep water environment in order to analyze its viability to provide data transmission for monitoring submarine equipment. The simulated scenario is located in the Campos Basin, Rio de Janeiro, on the Brazilian coast, responsible for more than 80% of Brazilian oil and gas production. Temperature and salinity data from five stations were used to calculate the sound speed profiles required to the transmission loss simulations of the acoustic propagation channel. In order to estimate the signal detection capacity according to the medium characteristics, a characterization of the parameters that influence the physical propagation channel was performed. The parameters of three modem models with different operation frequencies were selected and analyzed in order to obtain the Signal to Noise Ratio (SNR) of the transmission signal.

Analysis of a Collapse in Deep Tunnel Based on Microseismic Monitoring

2012 ◽  
Vol 256-259 ◽  
pp. 1181-1186 ◽  
Author(s):  
Guang Liang Feng ◽  
Xia Ting Feng ◽  
Zhou Neng Zhao ◽  
Guo Feng Liu ◽  
Ya Xun Xiao
Keyword(s):  
Average Distance ◽  
Moment Tensor ◽  
Case Analysis ◽  
Microseismic Monitoring ◽  
Typical Case ◽  
Economic Losses ◽  
Failure Evolution ◽  
Mixed Fracture ◽  
The Rich ◽  
Microseismic Event

Tunnel collapse causes serious casualties and economic losses. One typical case analysis of a collapse in deep-buried tunnel based on microseismic monitoring is presented. The results show that the number of microseismic event keeps increasing and the distribution of microseismic events becomes concentrated in space domain gradually during collapse nucleation process. And average distance squared decreases gradually during the imminent period time just before the collapse. The failure evolution mechanism of the collapse is analyzed by moment tensor method. It is noted that the failure mechanism between this kind of collapse and immediate strain-structure rockburst is similar. However, the proportion of shear and mixed fracture for collapse is higher than immediate strain-structure rockburst. It due to the rich structure planes in collapse zone.

Using the value of the crosscorrelation coefficient to locate microseismic events

Geophysics ◽  
2010 ◽  
Vol 75 (4) ◽  
pp. MA47-MA52 ◽  
Author(s):  
J. Kummerow
Keyword(s):  
Oil Recovery ◽  
Arrival Time ◽  
A Priori ◽  
Empirical Relation ◽  
Microseismic Monitoring ◽  
Seismic Events ◽  
Small Magnitude ◽  
Near Surface ◽  
Arrival Times ◽  
Receiver Array

A procedure to locate seismic events uses the value of the crosscorrelation coefficient between waveforms of different events. First, an empirical relation between spatial event separation and maximum crosscorrelation coefficient is established for a subset of a priori located reference events. Then this relation is used to determine the hypocenters of an increasing number of events by a grid-search strategy. Measured arrival-time differences between S- and P-waves also constrain the location. Although the reference events are located by a standard method using the arrival-time measurements at three or more receivers, the correlation-based location requires only one receiver. The method has been applied to microseismic data recorded at a single borehole sensor during the 2004/05 injection experiment at the Continental Deep Drilling Site (KTB) in Germany. With the approach, significantly more weak seismic events were located, compared to the number of events recorded by a near-surface receiver array and by inversion of arrival times. The proposed location method is particularly well suited to locate small-magnitude earthquakes within dense event clouds when too few arrival-time observations for part of the events are available and standard location methods fail. These conditions are frequently met in the case of microseismic monitoring of geothermal or enhanced oil recovery experiments.

Image-domain velocity inversion and event location for microseismic monitoring

Geophysics ◽  
2017 ◽  
Vol 82 (5) ◽  
pp. KS71-KS83 ◽  
Author(s):  
Ben Witten ◽  
Jeffrey Shragge
Keyword(s):  
Oil And Gas ◽  
Random Noise ◽  
Microseismic Monitoring ◽  
Seismic Events ◽  
S Wave ◽  
Origin Time ◽  
Image Domain ◽  
Velocity Inversion ◽  
Velocity Models ◽  
Event Location

Microseismic event locations obtained from seismic monitoring data sets are often a primary means of determining the success of fluid-injection programs, such as hydraulic fracturing for oil and gas extraction, geothermal projects, and wastewater injection. Event locations help the decision makers to evaluate whether operations conform to expectations or parameters need to be changed and may be used to help assess and reduce the risk of induced seismicity. However, obtaining accurate event location estimates requires an accurate velocity model, which is not available at most injection sites. Common velocity updating techniques require picking arrivals on individual seismograms. This can be problematic in microseismic monitoring, particularly for surface acquisition, due to the low signal-to-noise ratio of the arrivals. We have developed a full-wavefield adjoint-state method for locating seismic events while inverting for P- and S-wave velocity models that optimally focus multiple complementary images of recorded seismic events. This method requires neither picking nor initial estimates of event location or origin time. Because the inversion relies on (image domain) residuals that satisfy the differential semblance criterion, there is no requirement that the starting model be close to the true velocity. We determine synthetic results derived from a model with conditions similar to a field-acquisition scenario in terms of the number and spatial sampling of receivers and recorded coherent and random noise levels. The results indicate the effectiveness of the methodology by demonstrating a significantly enhanced focusing of event images and a reduction of 95% in event location error from a reasonable initial model.

Feasibility of monitoring hydraulic fracturing using time-lapse audio-magnetotellurics

Geophysics ◽  
2012 ◽  
Vol 77 (4) ◽  
pp. WB119-WB126 ◽  
Author(s):  
Lanfang He ◽  
Xiumian Hu ◽  
Ligui Xu ◽  
Zhanxiang He ◽  
Weili Li
Keyword(s):  
Hydraulic Fracturing ◽  
Case History ◽  
Oil And Gas ◽  
Signal To Noise Ratio ◽  
Time Lapse ◽  
Microseismic Monitoring ◽  
High Signal ◽  
Hydraulic Fractures ◽  
Industry Waste ◽  
Fracturing Process

Hydraulic fracturing is widely used for initiating and subsequently propagating fractures in reservoir strata by means of a pressurized fluid to release oil and gas or to store industry waste. Downhole or surface microseismic monitoring is commonly used to characterize the hydraulically induced fractures. However, in some cases, downhole microseismic monitoring can be difficult due to the limitation imposed by boreholes. Surface microseismic monitoring often faces difficulties acquiring high signal-to-noise ratio data because of the on-site noise from hydraulic fracturing process. Research and field observations indicate that injecting conductive slurry or water into a strata may generate distinct time-lapse electromagnetic anomalies between pre- and posthydraulic fracturing. These anomalies provide a means for characterizing the hydraulic fracturing using time-lapse electromagnetic methods. We examined the time-lapse variation over an hour, one day, one month, and two years of observed audio-magnetotellurics (AMT) resistivity and the 1D and 3D AMT modeling result of the variation pre- and posthydraulic fracturing. There is also a successful case history of applying the time-lapse AMT to map hydraulic fractures. Observed data indicate that the variation of AMT resistivity is normally less than 6% apart from the data of the dead band and some noisy data. Modeling results show the variation pre- and posthydraulic fracturing is larger than 30% at the frequency point lower than 100 Hz. The case history indicates that time-lapse magnetotelluric monitoring may form a new way to characterize the hydraulic fracture.

Regularization to Stein unbiased risk estimation denoising and threshold for first-break picking to low signal-to-noise ratio of surface microseismic monitoring — Case of gas shale fracturing

2020 ◽  
Vol 8 (2) ◽  
pp. SG51-SG60
Author(s):  
Qingming Xie ◽  
Hong Xu ◽  
Lichuan Chen ◽  
Hong Liu ◽  
Bolin Chen ◽  
...  
Keyword(s):  
Shale Gas ◽  
Signal To Noise Ratio ◽  
Risk Estimation ◽  
Microseismic Monitoring ◽  
Gas Production ◽  
Signal To Noise ◽  
Raw Data ◽  
Event Location ◽  
Noise Ratio ◽  
Unbiased Risk

With monitoring of the acoustic emission phenomenon caused by rock deformation and failure, microseismic monitoring has been widely used in the development of unconventional oil and gas fields. Due to the complex environment and diversity types of the noise, the signal energy of surface microseismic monitoring is weak and the signal-to-noise ratio (S/N) of raw data is very low. In the process of data processing, many human resources are needed to discriminate the first-break picking because of the low S/N, and this directly affects the error of microseismic event location. We have adopted the regularization to Stein unbiased risk estimation (R-SURE) algorithm based on the continuous wavelet transform to separate the signal from the noise in different decomposition levels. The regularization factor is the adaptive change of the different geology and fracturing engineering, which is related to shale brittleness, fracturing pressure, and displacement. As a result, the threshold from the R-SURE algorithm is multiresolution in different levels, and the S/N could be improved effectively. In addition, we established the threshold discriminant for picking up the first-break wave of low-S/N data combined with the Akaike information criterion and characteristic function, which compared the maximum absolute value in the time window. The method has good robustness and low computational complexity. The first arrival is automatically and accurately judged, which improves the accuracy of the event location. We successfully applied these methods to the surface microseismic monitoring of shale gas fracturing in several wells in southwest China. The S/N of the raw data has been improved, the effective stimulated reservoir volume and the performance of the gas production are predicted with the results, which provides important technical support for shale gas development in the area.

Numerical Analysis of the Induced Seismicity Triggered by Hydraulic Fracturing in the Duvernay Formation in Alberta, CA

2021 ◽  
Author(s):  
Dima Yassine ◽  
Alissar Yehya ◽  
Elsa Maalouf
Keyword(s):  
Hydraulic Fracturing ◽  
Pore Pressure ◽  
Observational Data ◽  
Induced Seismicity ◽  
Oil And Gas ◽  
The United States ◽  
Gas Production ◽  
Hydraulic Fractures ◽  
Seismic Events ◽  
Induced Earthquakes

<p>In the past decades, induced seismicity has become a major concern due to its correlation with oil and gas production and wastewater disposal. Unlike the induced seismicity observed in the United States that is associated with massive saltwater disposal, the induced seismicity observed in the Duvernay formation, a shale target in Alberta, Western Canada, is associated with hydraulic fracturing operations. In this work, we explore the possible mechanisms and the hydro-geological factors responsible for the seismic events that occurred between 2014 and 2015 in the Duvernay formation. By a two-dimensional finite element poroelastic model, using COMSOL Multiphysics, we couple fluid flow and solid deformation to estimate the change in the Coulomb Failure Stress (CFS) along two critically stressed faults existing near the hydraulic fracturing operations. One fault (Fault 1) is 1.01 km away from the location of hydraulic fractures while the second fault (Fault 2) is 0.425 km below the location of hydraulic fractures. The variations of the CFS along the two pre-existing faults are analyzed and compared to the seismic events obtained from the observational data in the Duvernay formation from December 2014 to March 2015 (Bao & Eaton, 2016). Our results show that most of the seismic events correlate spatially and temporally with positive CFS values that imply a risk of failure. During the early stages of hydraulic fracturing, the triggering failure mechanism of “Fault 1” is the increase in the shear stress on portions of the fault that are under extension and that of “Fault 2” is the pore pressure diffusion. Moreover, the distance between the centers of the two faults must range between 1.5 km and 2 km for the CFS results to agree with the observed seismic events. Under this condition, the shallower sections of “Fault 1” are under compression and show a stabilizing behavior (i.e., negative CFS) that is confirmed by the lack of seismic events from observational data, and the deeper sections of “Fault 1” are under extension and show a destabilizing behavior (i.e., positive CFS), which correlates with the measured seismic events. If the distance between “Fault 1” and “Fault 2” is less than 1.5 km, the shallower section of “Fault 1” would be destabilized by the effect of pore pressure, which does not agree with the observed seismic data. Moreover, if the distance between “Fault 1” and “Fault 2” is greater than 2 km, “Fault 1” would be entirely stabilized. Hence, the position of the faults with respect to the location of the hydraulic fracturing operations played an important role in the induced earthquakes triggering mechanisms and in the spatiotemporal distribution of the seismic events.</p>

Forecasting reservoir performance by mapping seismic emissions

2017 ◽  
Vol 5 (4) ◽  
pp. T451-T459 ◽  
Author(s):  
Charles Sicking ◽  
Jan Vermilye ◽  
Ashley Yaner
Keyword(s):  
Hydraulic Fracturing ◽  
Seismic Waves ◽  
Oil And Gas ◽  
Gas Production ◽  
Great Promise ◽  
Production Volume ◽  
Substantial Impact ◽  
Near Surface ◽  
Fracture Systems ◽  
Over Time

Streaming depth imaging (SDI) is a modified version of Kirchhoff migration that images the intensity and distribution of weak seismic waves emitted from rocks at depth. These images reveal the locations of the fractures and fracture networks in the reservoir. SDI allows for more informed forecasts for drilling, hydraulic fracturing, and reservoir management than is provided by traditional microearthquake mapping methods. Using passive data from surface and near-surface geophone grids, SDI integrates the seismic emissions over time to form the fracture activity volume. The fracture systems and the active production volume (APV) of the reservoir are calculated from this activity volume. In situ wellbore measurements indicate that the preexisting fracture systems in the reservoir rocks have substantial impact on the placement of the fluids during the hydraulic fracture treatment. They also strongly influence the locations of maximum oil and gas production and the decline rates of resource production. Mapping the fracture systems in the reservoir before drilling provides a strong forecasting value for optimal production sites for well placement. SDI can forecast hydraulic fracturing performance and improve the estimates of resource production volumes. Mapping the activity volumes during hydraulic fracturing shows the placement of the fluids during the treatment. SDI helps forecast the locations along the well that will have the best production. Time lapse mapping of the APV periodically during production shows the zones that are producing fluids and how they change over time. Our case histories indicate that this new seismic method has great promise for improved management of unconventional resources.

METHANE DETECTION FOR OIL AND GAS PRODUCTION SITES USING PORTABLE DUAL-COMB SPECTROMETRY

2016 ◽  
Author(s):  
Sean Coburn ◽  
Greg Rieker ◽  
Kuldeep Prasad ◽  
Subhomoy Ghosh ◽  
Caroline Alden ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Gas Production ◽  
Oil And Gas Production ◽  
Methane Detection
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