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- Volume 62, Issue 4, 2014
Geophysical Prospecting - 4 - Vertical Seismic Profiling and Microseismicity Frontiers, 2014
4 - Vertical Seismic Profiling and Microseismicity Frontiers, 2014
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Distributed acoustic sensing for reservoir monitoring with vertical seismic profiling
ABSTRACTDistributed Acoustic Sensing is a novel technology for seismic data acquisition, particularly suitable for Vertical Seismic Profiling. It is a break‐through for low‐cost, on‐demand, seismic monitoring of reservoirs, both onshore and offshore.
In this article we explain how Distributed Acoustic Sensing works and demonstrate its usability for typical Vertical Seismic Profiling applications such as checkshots, imaging, and time‐lapse monitoring. We show numerous data examples, and discuss Distributed Acoustic Sensing as an enabler of seismic monitoring with 3D Vertical Seismic Profiling.
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Vertical seismic optical profiling on wireline logging cable
Authors Arthur Hartog, Bernard Frignet, Duncan Mackie and Mike ClarkABSTRACTVertical seismic profiles are usually acquired by deploying downhole seismic sensors below a wireline logging cable. A seismic source is triggered at surface while recording the downhole vibration via the wireline cable. In this paper, an alternative approach based on distributed vibration measurement is tested using wireline deployment for the first time.
Local axial strain of a multi‐kilometre fibre optic line is measured at intervals of approximately 1 m and processed to a spatial resolution of 10 m with sub nanometer strain resolution by an optical interrogation device (distributed vibration/acoustic sensing). When deployed in a well, the optical fibre line should be mechanically coupled to the borehole wall to generate valid seismic records.
A conventional vertical seismic profile was acquired with three‐component sensors in a vertical well near Bottesford, UK. The impulsive seismic source was a novel portable airgun tank. Clear seismic reflections are observed within and below the borehole, in agreement with surface seismic data. A single shot generated equivalent data with an experimental optical wireline logging cable and an adequate optical interrogator at the surface. The main difference between the two records is the presence of a strong tube wave in the optical profile, which can be easily removed with conventional velocity filter processing. Corridor stacks from both conventional and optical profiles match each other and provide a reasonable tie to a nearby surface seismic line.
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Drill‐bit seismic monitoring while drilling by downhole wired‐pipe telemetry
Authors Flavio Poletto, Francesco Miranda, Piero Corubolo, Andrea Schleifer and Paolo ComelliABSTRACTDrill‐bit seismic while drilling provides reverse vertical seismic profiles with large configurations of surface seismic sensors. This seismic while drilling technique makes it possible to predict the formation changes ahead of the bit and to image 2D and 3D structures without interfering with the drilling activity. The method is based on the recording of reference (pilot) signals which enable us to recognize and process the signal of the downhole drill‐bit source, thus obtaining impulsive seismograms after the crosscorrelation and deconvolution of the pilot signals and the seismic data recorded by surface or crosswell geophones. One issue in the application of this methodology can be the loss of the transmitted energy for the reference signal propagated from the bit to the surface through the drill string, when the pilot signals are recorded at the surface, at the top of the drill string. It is well known that with polycrystalline diamond compact bits, the pilot signal recorded at the surface may be weak and consequently the seismic while drilling results are poor. This may also happen during drilling in the sliding mode without pipe rotation, and in highly deviated or horizontal wells. A solution to improve the drill‐bit seismic while drilling method in these conditions is to record the reference signal in the proximity of the bit source, using downhole near‐bit tools to get good‐quality measurements of the pilot signal. We present drill‐bit seismic while drilling results obtained in a drilling test using wired pipes for high‐rate communication from bottom hole to the surface. The results demonstrate the applicability of this integrated approach as a standard procedure. The advantage of this is to provide real‐time synchronized reverse vertical seismic profiles, as well as high‐resolution and good‐quality data in terms of S/N and high‐frequency content. The method improves the use of the working drill bit as a downhole seismic source with different types of bit and drilling conditions.
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Borehole seismic quantitative diagnosis of a seismic velocity model for 3D seismic imaging of subsurface structures
Authors Yingping Li and Ben HewettABSTRACTQuantifying uncertainties of surface seismic velocity models is a difficult task. The use of multifarious vertical seismic profiling data provides quantification of velocity model uncertainties. Two borehole seismic diagnosis methods for velocity model uncertainties are developed. The first method is performed with 3D ray‐traced first arrival times through a surface seismic velocity model and compared with measured first arrival times from downhole receivers. It generates a profile of absolute and relative misfits, indicating the velocity uncertainty as a function of depth. The second approach directly compares the differences between the first arrival incident angles measured from 3‐C borehole seismic data and the calculated first arrival incident angles of seismic rays through the velocity model to quantify the model uncertainties. Five seismic velocity models in the Gulf of Mexico are diagnosed using the diagnosis methods with up to six sets of borehole seismic data recorded in three wells. The uncertainty profiles vary with depths and azimuths, revealing the complexity of velocity model uncertainties and providing some clues for further velocity updating. The diagnosis methods are used as velocity updating QC tools and integrated with the conventional seismic velocity updating flow to complement the criteria of flat common image gathers.
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Full‐wavefield migration of vertical seismic profiling data: using all multiples to extend the illumination area
Authors A.K. Soni and D.J. VerschuurABSTRACTVertical seismic profiling data can provide a high‐resolution reservoir image because the receivers are located close to the reservoir and, hence, the wavefield encounters less distortion in the overburden compared to surface seismic data. However, conventional migration of vertical seismic profiling data using only upgoing primary wavefields often suffers from poor illumination, imaging artefacts and low image reliability, especially at image locations away from the well. We propose full‐wavefield migration to image vertical seismic profiling data using the primaries and all orders of surface multiples and internal multiples. The downgoing internal or surface multiples are treated as an additional source of illumination. In full‐wavefield migration, we aim to estimate a high‐resolution reflectivity image of the subsurface with this extended illumination. The algorithm is recursive in depth like conventional wavefield extrapolation‐based migration, however, it incorporates the non‐linear transmission and scattering effects at each depth level. Further, full‐wavefield migration is posed as a constrained least‐squares inversion problem that could be solved using a conjugate gradient method. We propose an iterative full‐wavefield forward modelling engine as the backbone of this inversion scheme. The parameter used in the modelling is subsurface reflectivity. Full‐wavefield modelling iteratively incorporates the non‐linearity of the wavefield due to multiple scattering, where every iteration utilizes one higher order of scattered wavefields to estimate the subsurface reflectivity. In addition, the constrained inversion helps in reducing the extrapolation artefacts and provides a high‐resolution image of the reservoir. In this paper, we discuss the concept of full‐wavefield migration and demonstrate its potential as an imaging tool for vertical seismic profiling data using synthetic examples.
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Reservoir monitoring of steam‐assisted gravity drainage using borehole measurements
ABSTRACTThis paper presents the results from a research project focusing on permanent cross‐well geophysical methods for reservoir monitoring during steam‐assisted gravity drainage. A feasibility study indicated detectable differences in seismic and electrical reservoir properties based on expected changes in temperature and fluid saturation during the production of extra heavy oil. As a result of this, a permanent cross‐well system was installed at the Leismer Demonstration Area, located in the Athabasca Oil Sands region in Alberta, Canada. Baseline data sets, including cross‐well seismic, three‐dimensional vertical seismic profiling and cross‐well electrical resistivity tomography, have been acquired. Comparisons between conventional surface seismic and downhole seismic data show an increase in resolution and frequency content as expected. Steam‐assisted gravity drainage‐induced time‐lapse effects are clearly visible in the 3D vertical seismic profiling and electrical resistivity tomography data sets, even after a few months of oil production. In general, the 3D vertical seismic profiling images show a higher resolution than the surface seismic data, in particular when dealing with vertical positioning of the time‐lapse events. The electrical resistivity tomography baseline shows clear separation between zones of high and low electrical resistivity, and during 23 months of electrical resistivity tomography measurements the maximum reduction of resistivity is 85%. Time‐lapse observations from acoustic and electrical borehole data correspond well, and are also supported by temperature measurements in the two observation wells. Emerging technologies, updated models, improved flexibility, and reduced costs will allow future reservoir monitoring with surface and borehole data in combination, or even with borehole data exclusively.
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Characterization of fractures and faults: a multi‐component passive microseismic study from the Ekofisk reservoir
Authors G.A. Jones, J.‐M. Kendall, I. Bastow, D.G. Raymer and A. WuestefeldABSTRACTFractures and faults within a reservoir can provide important pathways for the movement of reservoir fluids. Understanding the character and properties of these features on a range of length scales can be vital for the efficient exploitation of natural resources, whether it be enhanced oil and gas recovery, the safe storage of CO2, or better exploitation of geothermal heat. The monitoring of microseismicity within a reservoir illuminates active faults, but these events can be also used to characterize fracture networks through measurements of seismic anisotropy. In this study we use microseismic data acquired over an 18‐day period in April 1997 at the Ekofisk oil field in the North Sea. Using the analysis of seismic multiplets we delineate a number of sub‐vertical tectonic faults, which are consistent with previous core data analysis and seismic reflection work. We use shear wave splitting measurements, which are indicative of fracture‐induced seismic anisotropy, to infer the orientation of aligned aseismic fracture sets within the reservoir. The estimated fracture dip and strike from the shear wave splitting analysis are consistent with the active tectonic fractures characterized by the multiplets, but this analysis also illuminates spatial variations in fracture properties. Such monitoring on a longer term and with multiple wells is a promising tool for better understanding fracture and fault‐controlled flow within reservoirs.
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The influence of fracturing process on microseismic propagation
Authors Xiaolin Zhang, Feng Zhang and Xiang‐Yang LiABSTRACTIn the hydraulic fracturing process, the velocity model for microseismic location is usually constructed by well logs, seismic data or calibration shots which ignore the influence of the fracturing process. In this work, we examine its influence by simulating microseismic events and pore pressure variation in the fracturing process. Besides the microseismicity produced by hydraulic fracture extension, we also simulate the microseismicity caused by fluid leakage by means of the critical pore pressure criterion. The Coates‐Schoenberg method and fracture compliances are then applied to calculate the real‐time velocity in the fracturing process, and 3D ray tracing method is applied to compare the microseismic propagation variation in the different stages of the fracturing process. The results of the simulation show that the deviation caused by the fracturing process varies considerably between different receiver locations, and the overall deviation increases with the fracturing process. Finally, a new method is constructed to evaluate the travel time deviation in real data.
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Breakdown of the Gutenberg‐Richter relation for microearthquakes induced by hydraulic fracturing: influence of stratabound fractures
Authors David W. Eaton, Jörn Davidsen, Per Kent Pedersen and Neda BoroumandABSTRACTHydraulic fracturing, a powerful completion technique used to enhance oil or gas production from impermeable strata, may trigger unintended earthquake activity. The primary basis for assessment of triggered and natural seismic hazard is the classic Gutenberg‐Richter (G‐R) relation, which expresses scale‐independent behaviour of earthquake magnitudes. Here we use a stochastic approach to simulate and test magnitude‐distance trends expressed by microseismic catalogues derived from three hydraulic fracture monitoring programmes in North America. We show that a widely observed rapid fall‐off in large‐magnitude events, almost universally quantified using the G‐R b value, may in our case be an artefact of the strongly laminated character of the stimulated oil and gas reservoirs. We also show that, for the three reservoirs considered, mechanical bed thickness can be approximated by a lognormal distribution. For a stratabound fracture network, this leads asymptotically to a Gaussian decay for induced magnitudes. We show that the stratabound model provides a more significant correspondence with our observations. If applicable in general, this result has important implications for determining the energy balance of hydraulic fracture systems (i.e. radiated seismic energy versus injected energy) as well as hazard assessments based on the probability of occurrence of anomalous seismic events.
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Passive surface microseismic monitoring as a statistical problem: location of weak microseismic signals in the presence of strongly correlated noise
Authors Alexander Kushnir, Alexander Varypaev, Ilya Dricker, Mikhail Rozhkov and Nikita RozhkovABSTRACTIn this paper, we treat passive surface microseismic monitoring as a predominantly statistical problem of location sources of weak seismicity recorded in the presence of strongly correlated noise using dense seismic arrays. We introduce two statistically optimal algorithms (adaptive maximal likelihood algorithm and statistically optimal phase algorithm) and show that the traditional semblance‐based microseismic processing algorithm (Seismic Emission Tomography) is just an extreme case of the maximal likelihood algorithm for Gaussian white noise (i.e., noise that is stationary and uncorrelated in time and space). We evaluate location uncertainties of all three microseismic algorithms for different types of noise patterns and signal‐to‐noise ratios. For Gaussian white noise, the Seismic Emission Tomography algorithm performs well, demonstrating even slightly better location accuracy than statistically optimal techniques. Actual noise affecting seismic sensors during hydraulic fracturing is non‐stationary. It is correlated in time and space, and varies greatly in power and spectral content for different sensors of the array. We use Monte Carlo simulation to show that the location accuracy of statistically optimal algorithms can be 20 to 40 times better than for the Seismic Emission Tomography algorithm in the presence of man‐made surface noise during hydraulic fracturing.
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Novel hybrid artificial neural network based autopicking workflow for passive seismic data
Authors Debotyam Maity, Fred Aminzadeh and Martin KarrenbachABSTRACTMicroseismic monitoring is an increasingly common geophysical tool to monitor the changes in the subsurface. Autopicking involving phase arrival detection is a common element in microseismic data processing schemes and is necessary for accurate estimation of event locations as well as other workflows such as tomographic or moment tensor inversion, etc. The quality of first arrival picking is dependent on the actual seismic waveform, which in turn is related to the near surface and subsurface structure, source type, noise conditions, environmental factors, and monitoring array design, etc. We have developed a new hybrid autopicking workflow which makes use of multiple derived attributes from the seismic data and combines them within an artificial neural network framework. An evolutionary algorithm scheme is used as the network training algorithm. The autopicker has been tested and its applicability has been validated using a synthetically modelled seismic source, with promising results. In this work, we share the basic workflow and different attributes that have been tested with this algorithm for a synthetic data set to provide a framework for independent implementation, use and validation. We also compare the results obtained using the new neural network based autopicking routine with very robust contemporary autopicking algorithms in use within the industry.
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Bias in magnitude for earthquakes with unknown focal mechanism
By G. DanielABSTRACTThis study investigates errors induced by the use of average double‐couple radiation coefficients for the computation of earthquake magnitude. Indeed, when an earthquake focal mechanism cannot be anticipated before calculating its magnitude, we show that the induced error depends on several factors such as event location, monitoring network aperture, type of seismic phase involved in the calculation (P/S waves) and focal mechanism. Energy radiated at lower amplitude is less likely to be observed, so, applying an absolute lower bound on radiation equal to 0.1, we show that errors in magnitude are expected to range within the [−0.5; 0.2] interval. This indicates that errors have a stronger tendency towards under‐estimation than over‐estimation. We also present simulations of the spatial distribution of such errors for two double‐couple mechanisms and one tensile opening, which reveal strong spatial dependencies on: i) the radiation pattern; and ii) the coverage of the focal sphere by the monitoring network. We show that the variability of errors significantly decreases with increasing network aperture. We apply this procedure to a field dataset, namely the monitoring of hydraulic fracturing in the Cotton Valley formation of Texas. In this case, if event focal mechanisms were not accounted for, errors in magnitude would generally fall within the above‐mentioned interval; except for a few events presenting a larger under‐estimation (error would reach when the magnitude is computed using P waves only). A clear spatial pattern of errors is also observed at the Cotton Valley project, characterized by a west‐to‐east change in error polarity, but presenting a non‐varying pattern in depth. Finally, such errors in magnitude have an insignificant impact on frequency‐size distribution of events. b‐value estimates based on such frequency‐size distributions are within the uncertainty domain of estimates based on corrected frequency‐size distributions.
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The robustness of seismic moment and magnitudes estimated using spectral analysis
Authors A.L. Stork, J.P. Verdon and J.‐M. KendallABSTRACTWe present an assessment of how microseismic moment magnitude, , estimates vary with the method and parameters used to calculate seismic moment. This is an important topic for operators and regulators who require good magnitude estimates when monitoring induced seismicity. It is therefore imperative that these parties know and understand what errors exist in given magnitude values, something that is poorly reported. This study concentrates on spectral analysis techniques and compares computed in the time and frequency domains. Using recordings of events at Cotton Valley, east Texas, the maximum discrepancy between estimated using the different methods is 0.6 units, a significant variation. By adjusting parameters in the calculation we find that the radiation pattern correction term can have the most significant effect on , generally up to 0.8 units. Following this investigation we make a series of recommendations for estimating microseismic using spectral methods. Noise should be estimated and removed from recordings and an attenuation correction should be applied. The spectral level can be measured by spectral fitting or taken from the low frequency level. Significant factors in obtaining reliable microseismic estimates include using at least four receivers recording at ⩾1000 Hz and making radiation pattern corrections based on focal mechanism solutions, not average values.
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Moment tensor migration imaging
Authors Kit Chambers, Ben D.E. Dando, Glenn A. Jones, Raquel Velasco and Stephen A. WilsonABSTRACTWe develop and apply an imaging procedure for simultaneous location and characterization of seismic source properties called Moment Tensor Migration Imaging. The procedure constructs images for moment tensor components using a weighted diffraction stack migration, and combines ray‐theoretical Green's functions with a reverse time moment tensor imaging methodology. By applying an approximation we term the ‘ray‐angles only approximation’, we form an expression for Moment Tensor Migration Imaging where the migration weights depend only on the take‐off and arrival angles for rays leaving receiver positions and incident upon the image points. Moment Tensor Migration Imaging retains the benefits of diffraction stack procedures for source location and characterization, namely speed, flexibility, and the potential for incorporating non‐linear stacking procedures, whilst also providing the benefits of moment tensor imaging such as: the inclusion of multiple phase and multiple component data; the collapsing of the source radiation pattern; estimation of the moment tensor.
We examine variations of the imaging procedure through a synthetic test. We show that although the assumptions required for the imaging and ray‐angles only approximation may not be strictly valid for realistic survey geometries, a simple weight adjustment can be used to obtain more accurate and stable results in these situations. In our synthetic example we find that the use of a P‐wave only migration without this reweighting structure produces poor results, whereby the resulting images show activity upon incorrect moment tensor components. However, many of these effects are mitigated by use of the reweighting scheme and the results are further improved through the introduction of non‐linear stacking operators such as semblance weighted stacks. The highest quality moment tensor images (for the synthetic test examined here) are obtained through the use of both P‐wave and S‐wave wave fields. This highlights the importance of multicomponent data and multiphase modelling when characterizing seismic sources. We also find that the imaged moment tensor components vary proportionately when the input velocities are perturbed by a scale factor. This suggests, for the geometry investigated here, derived source properties such as fault‐plane solutions and shear‐tensile components will not be influenced by bulk changes in seismic velocities. Finally, we show the application to a real microseismic event observed using a surface array during hydraulic fracturing. We find that the procedure collapses the seismic radiation pattern into an anomaly with a maximum at the hypocentre and our derived mechanism is consistent with the observed radiation pattern from the source.
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On the use of microtremors for hydrocarbon detection
Authors A. Vesnaver, F. Da Col, M. Jervis, S.I. Kaka and D. NietoABSTRACTThe link of spectral anomalies of microtremors to underlying hydrocarbon reservoirs is very controversial, as field experiments support both positive and negative opinions, and there is not a solid theory supporting this work hypothesis. We conducted field tests at different sites, with and without oil and gas presence, to add new experimental data to the ongoing studies. Microtremor information may become repeatable (and so physically meaningful) only when the observation duration exceeds a few days, but even in this case, factors such as topography and active faults may severely bias the signal.
Ocean waves impinging the coasts provide natural background noise, which stands out clearly when the observation time exceeds a dozen days or so, in such a way that human noise is stacked out statistically over time.
Microtremors recorded in (relatively) deep wells may provide useful information about ongoing production in a reservoir, and may link well data and seismic surveys, as their interferometric analysis can provide information comparable to Vertical Seismic Profiles.
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