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- Volume 58, Issue 5, 2010
Geophysical Prospecting - Volume 58, Issue 5, 2010
Volume 58, Issue 5, 2010
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Improved microseismic event location by inclusion of a priori dip particle motion: a case study from Ekofisk
Authors G.A. Jones, D. Raymer, K. Chambers and J.‐M. KendallABSTRACTMicroseismic monitoring in petroleum settings provides insights into induced and naturally occurring stress changes. Such data are commonly acquired using an array of sensors in a borehole, providing measures of arrival times and polarizations. Events are located using 1D velocity models, P‐ and S‐wave arrival times and the azimuths of P‐wave particle motions. However in the case of all the sensors being deployed in a vertical or near‐vertical borehole, such analysis leads to an inherent 180° ambiguity in the source location. Here we present a location procedure that removes this ambiguity by using the dip of the particle motion as an a priori information to constrain the initial source location. The new procedure is demonstrated with a dataset acquired during hydraulic fracture stimulation, where we know which side of the monitoring well the events are located. Using a 5‐step location procedure, we then reinvestigate a microseismic data set acquired in April 1997 at the Ekofisk oilfield in the North Sea. Traveltimes for 2683 candidate events are manually picked. A noise‐weighted analytic‐signal polarization analysis is used to estimate the dip and azimuth of P‐wave particle motions. A modified t‐test is used to statistically assess the reliability of event location. As a result, 1462 events are located but 627 are deemed to be statistically reliable. The application of a hierarchal cluster analysis highlights coherent structures that cluster around wells and inferred faults. Most events cluster at a depth of roughly 3km in the Ekofisk chalk formation but very little seismicity is observed from the underlying Tor chalk formation, which is separated from the Ekofisk formation by an impermeable layer. We see no evidence for seismicity in the overburden but such events may be too distant to detect. The resulting picture of microseismicity at Ekofisk is very different from those presented in previous studies.
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Constrained tomography of realistic velocity models in microseismic monitoring using calibration shots
Authors T. Bardainne and E. GaucherABSTRACTThe knowledge of the velocity model in microseismic jobs is critical to achieving statistically reliable microseismic event locations. The design of microseismic networks and the limited sources for calibration do not allow for a full tomographic inversion. We propose optimizing a priori velocity models using a few active shots and a non‐linear inversion, suitable to poorly constrained systems. The considered models can be described by several layers with different P‐ and S‐wave velocities. The velocities may be constant or have 3D gradients; the layer interfaces may be simple dipping planes or more complex 3D surfaces. In this process the P‐ and S‐ wave arrival times and polarizations measured on the seismograms constitute the observed data set. They are used to estimate two misfit functions: i) one based on the measurement residuals and ii) one based on the inaccuracy of the source relocation. These two functions are minimized thanks to a simulated annealing scheme, which decreases the risk of converging to a local solution within the velocity model.
The case study used to illustrate this methodology highlights the ability of this technique to constrain a velocity model with dipping layers. This was performed by jointly using sixteen perforation shots recorded during a multi‐stage fracturing operation from a single string of 3C‐receivers. This decreased the location inaccuracies and the residuals by a factor of six. In addition, the retrieved layer dip was consistent with the pseudo‐horizontal trajectories of the wells and the background information provided by the customer. Finally, the theoretical position of each calibration shot was contained in the uncertainty domain of the relocation of each shot. In contrast, single‐stage inversions provided different velocity models that were neither consistent between each other nor with the well trajectories. This example showed that it is essential to perform a multi‐stage inversion to derive a better updated velocity model.
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A strategy for automated analysis of passive microseismic data to image seismic anisotropy and fracture characteristics
More LessABSTRACTMonitoring of induced seismicity is gaining importance in a broad range of industrial operations from hydrocarbon reservoirs to mining to geothermal fields. Such passive seismic monitoring mainly aims at identifying fractures, which is of special interest for safety and productivity reasons. By analysing shear‐wave splitting it is possible to determine the anisotropy of the rock, which may be caused by sedimentary layering and/or aligned fractures, which in turn offers insight into the state of stress in the reservoir. We present a workflow strategy for automatic and effective processing of passive microseismic data sets, which are ever increasing in size. The automation provides an objective quality control of the shear‐wave splitting measurements and is based on characteristic differences between the two independent eigenvalue and cross‐correlation splitting techniques. These differences are summarized in a quality index for each measurement, allowing identification of an appropriate quality threshold. Measurements above this threshold are considered to be of good quality and are used in further interpretation. We suggest an automated inversion scheme using rock physics theory to test for best correlation of the data with various combinations of fracture density, its strike and the background anisotropy. This fully automatic workflow is then tested on a synthetic and a real microseismic data set.
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Assessment of focal mechanisms of microseismic events computed from two three‐component receivers: application to the Arkema‐Vauvert field (France)
Authors M. Godano, E. Gaucher, T. Bardainne, M. Regnier, A. Deschamps and M. ValetteABSTRACTWe have developed a method that enables computing double‐couple focal mechanisms with only a few sensors. This method is based on a non‐linear inversion of the P, Sv and Sh amplitudes of microseismic events recorded on a set of sensors. The information brought by the focal mechanism enables determining the geometry of the rupture on the associated geological structure. It also provides a better estimate of the conventional source parameters. Full analysis has been performed on a data set of 15 microseismic events recorded in the brine production field of Vauvert. The microseismic monitoring network consisted of two permanent tools and one temporary borehole string. The majority of the focal mechanisms computed from both permanent tools are similar to those computed from the whole network. This result indicates that the double‐couple focal mechanism determination is reliable for both permanent 3C receivers in this field.
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Application of microseismic multiplet analysis to the Basel geothermal reservoir stimulation events
Authors B.C. Dyer, U. Schanz, T. Spillmann, F. Ladner and M.O. HäringABSTRACTThe stimulation of a geothermal well in Basel, Switzerland produced a distribution of microseismic event locations with an overall alignment in the direction of the maximum horizontal stress. Fault plane solutions of individual larger events indicated movements on fracture planes at an angle to the maximum horizontal stress that could not be reliably interpreted from the event locations. To obtain higher resolution images of the microseismic event locations, events with similar waveforms have been identified by multiplet analysis. A number of receivers were used in the multiplet processing to ensure each multiplet is represented by a unique group of waveforms. The location accuracy within each multiplet has been significantly improved using cross‐correlation to refine the shear‐wave traveltime picks. The distribution of events within each multiplet can be interpreted as being due to movements on a single fracture or a number of near parallel fractures. It is shown that whilst the overall distribution of events is around the direction of the maximum horizontal stress, the individual multiplets representing fracture planes have a variety of azimuths and dips.
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Comparison of surface and borehole locations of induced seismicity
Authors Leo Eisner, B. J. Hulsey, Peter Duncan, Dana Jurick, Heigl Werner and William KellerABSTRACTMonitoring of induced microseismic events has become an important tool in hydraulic fracture diagnostics and understanding fractured reservoirs in general. We compare microseismic event and their uncertainties using data sets obtained with surface and downhole arrays of receivers. We first model the uncertainties to understand the effect of different acquisition geometries on location accuracy. For a vertical array of receivers in a single monitoring borehole, we find that the largest part of the final location uncertainty is related to estimation of the backazimuth. This is followed by uncertainty in the vertical position and radial distance from the receivers. For surface monitoring, the largest uncertainty lies in the vertical position due to the use of only a single phase (usually P‐wave) in the estimation of the event location. In surface monitoring results, lateral positions are estimated robustly and are not sensitive to the velocity model.
In this case study, we compare event location solutions from two catalogues of microseismic events; one from a downhole array and the second from a surface array of 1C geophone. Our results show that origin time can be reliably used to find matching events between the downhole and surface catalogues. The locations of the corresponding events display a systematic shift consistent with a poorly calibrated velocity model for downhole dataset. For this case study, locations derived from surface monitoring have less scatter in both vertical and horizontal directions.
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Testing the ability of surface arrays to monitor microseismic activity
Authors Kit Chambers, J.‐Michael Kendall, Sverre Brandsberg‐Dahl and Jose RuedaABSTRACTRecently there has been much interest in the use of data from surface arrays in conjunction with migration‐based processing methods for passive seismic monitoring. In this study we use an example of this kind of data recorded whilst 18 perforation shots, with a variety of positions and propellant amounts, were detonated in the subsurface. As the perforation shots provide signals with known source positions and origin times, the analysis of these data is an invaluable opportunity to test the accuracy and ability of surface arrays to detect and locate seismic sources in the subsurface. In all but one case the signals from the perforation shots are not visible in the raw or preprocessed data. However, clear source images are produced for 12 of the perforation shots showing that arrays of surface sensors are capable of imaging microseismic events, even when the signals are not visible in individual traces. We find that point source locations are within typically 45 m (laterally) of the true shot location, however the depths are less well constrained (∼150 m). We test the sensitivity of our imaging method to the signal‐to‐noise ratio in the data using signals embedded in realistic noise. We find that the position of the imaged shot location is quite insensitive to the level of added noise, the primary effect of increased noise being to defocus the source image. Given the migration approach, the array geometry and the nature of coherent noise during the experiment, signals embedded in noise with ratios ≥0.1 can be used to successfully image events. Furthermore, comparison of results from data and synthetic signals embedded in noise shows that, in this case, prestack corrections of traveltimes to account for near‐surface structure will not enhance event detectability. Although, the perforation shots have a largely isotropic radiation pattern the results presented here show the potential for the use of surface sensors in microseismic monitoring as a viable alternative to classical downhole methods.
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Joint 3D processing of active and passive seismic data
Authors Aldo Vesnaver, Lara Lovisa and Gualtiero BöhmABSTRACTPassive seismic provides additional illumination sources in producing reservoirs, improving the Earth's imaging obtained by standard 3D seismic surveys. The joint tomographic inversion of surface and borehole data, both active and passive, even allows the delineation of thin reservoirs that cannot be resolved by reflection tomography. As an application example, we present a feasibility study for a real case of CO2 geological storage, showing that this operation may benefit both environment and reservoir monitoring.
The origin time of micro‐earthquakes due to production operations is critical for merging active and passive data. We show here that the Wadati's method is not accurate for borehole data in a layered earth model, when the ratio between P and S velocities is not constant, as occurs in most hydrocarbon reservoirs. This drawback can be solved by deploying a few receivers at the surface close to the well.
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Intrinsic Qp seismic attenuation from the rise time of microearthquakes: a local scale application at Rio‐Antirrio, Western Greece
Authors G.‐Akis Tselentis, Paraskevas Paraskevopoulos and Nikos MartakisABSTRACTWe determine the attenuation structure of a three‐dimensional medium based on first pulse‐width measurements from microearthquake data. Ninety‐five microearthquakes from a seventy stations local network were considered in this study. Measurements of the first half cycle of the wave, the so‐called rise time τ were carried out on high quality velocity seismograms and inverted to estimate the P‐waves intrinsic quality factor Qp. The results of this investigation indicate that first pulse width data from a local microearthquake network permit retrieval with sufficient accuracy of the heterogeneous Qp structure. The inferred attenuation variability corresponds to the known geological formations in the region.
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Source location using time‐reverse imaging
Authors Brad Artman, Igor Podladtchikov and Ben WittenABSTRACTWe present the chain of time‐reverse modeling, image space wavefield decomposition and several imaging conditions as a migration‐like algorithm called time‐reverse imaging. The algorithm locates subsurface sources in passive seismic data and diffractors in active data. We use elastic propagators to capitalize on the full waveforms available in multicomponent data, although an acoustic example is presented as well. For the elastic case, we perform wavefield decomposition in the image domain with spatial derivatives to calculate P and S potentials. To locate sources, the time axis is collapsed by extracting the zero‐lag of auto and cross‐correlations to return images in physical space. The impulse response of the algorithm is very dependent on acquisition geometry and needs to be evaluated with point sources before processing field data. Band‐limited data processed with these techniques image the radiation pattern of the source rather than just the location. We present several imaging conditions but we imagine others could be designed to investigate specific hypotheses concerning the nature of the source mechanism. We illustrate the flexible technique with synthetic 2D passive data examples and surface acquisition geometry specifically designed to investigate tremor type signals that are not easily identified or interpreted in the time domain.
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Low‐frequency passive seismic experiments in Abu Dhabi, United Arab Emirates: implications for hydrocarbon detection
Authors Mohammed Y. Ali, Karl A. Berteussen, James Small and Braham BarkatABSTRACTLow‐frequency passive seismic experiments utilizing arrays of 3‐component broadband seismometers were conducted over two sites in the emirate of Abu Dhabi in the United Arab Emirates. The experiments were conducted in the vicinity of a producing oilfield and around a dry exploration well to better understand the characteristics and origins of microtremor signals (1–6 Hz), which had been reported as occurring exclusively above several hydrocarbon reservoirs in the region.
The results of the experiments revealed that a strong correlation exists between the recorded ambient noise and observed meteorological and anthropogenic noises. In the frequency range of 0.15–0.4 Hz, the dominant feature is a double‐frequency microseism peak generated by the non‐linear interactions of storm induced surface waves in the Arabian Sea. We observed that the double‐frequency microseism displays a high variability in spectral amplitude, with the strongest amplitude occurring when Cyclone Gonu was battering the eastern coast of Oman; this noise was present at both sites and so is not a hydrocarbon indicator. Moreover, this study found that very strong microtremor signals in the frequency range of 2–3 Hz were present in all of the locations surveyed, both within and outside of the reservoir boundary and surrounding the dry exploration well. This microtremor signal has no clear correlation with the microseism signals but significant variations in the characteristics of the signals were observed between daytime and nighttime recording periods that clearly correlate with human activity.
High‐resolution frequency‐wavenumber (f‐k) spectral analyses were performed on the recorded data to determine apparent velocities and azimuths of the wavefronts for the microseism and microtremor events. The f‐k analyses confirmed that the double‐frequency microseism originates from wave activity in the Arabian Sea, while the microtremor events have an azimuth pointing towards the nearest motorways, indicating that they are probably being excited by traffic noise. Results drawn from particle motion studies confirm these observations. The vertical‐to‐horizontal spectral ratios of the data acquired in both experiments show peaks around 2.5–3 Hz with no dependence on the presence or absence of subsurface hydrocarbons. Therefore, this method should not be used as a direct hydrocarbon indicator in these environments. Furthermore, the analyses provide no direct evidence to indicate that earthquakes are capable of stimulating the hydrocarbon reservoir in a way that could modify the spectral amplitude of the microtremor signal.
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Modelling microseismicity of a producing reservoir from coupled fluid‐flow and geomechanical simulation
Authors D.A. Angus, J.‐M. Kendall, Q.J. Fisher, J.M. Segura, S. Skachkov, A.J.L. Crook and M. DutkoABSTRACTIn this paper, we investigate production induced microseismicity based on modelling material failure from coupled fluid‐flow and geomechanical simulation. The model is a graben style reservoir characterized by two normal faults subdividing a sandstone reservoir into three compartments. The results are analysed in terms of spatial and temporal variations in distribution of material failure. We observe that material failure and hence potentially microseismicity is sensitive to not only fault movement but also fluid movement across faults. For sealing faults, failure is confined to the volume in and around the well compartment, with shear failure localized along the boundaries of the compartment and shear‐enhanced compaction failure widespread throughout the reservoir compartment. For non‐sealing faults, failure is observed within and surrounding all three reservoir compartments as well as a significant distribution located near the surface of the overburden. All shear‐enhanced compaction failures are localized within the reservoir compartments. Fault movement leads to an increase in shear‐enhanced compaction events within the reservoir as well as shear events located within the side‐burden adjacent to the fault. We also evaluate the associated moment tensor mechanisms to estimate the pseudo scalar seismic moment of failure based on the assumption that failure is not aseismic. The shear‐enhanced compaction events display a relatively normal and tight pseudo scalar seismic moment distribution centred about 106 Pa, whereas the shear events have pseudo scalar seismic moments that vary over three orders of magnitude. Overall, the results from the study indicate that it may be possible to identify compartment boundaries based on the results of microseismic monitoring.
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Volumes & issues
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Volume 72 (2023 - 2024)
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Volume 71 (2022 - 2023)
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Volume 70 (2021 - 2022)
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Volume 69 (2021)
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Volume 68 (2020)
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Volume 67 (2019)
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Volume 63 (2015)
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Volume 61 (2013)
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Volume 60 (2012)
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Volume 59 (2011)
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Volume 58 (2010)
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