Seismic-while-drilling by drill-bit source and large-aperture ocean-bottom array

Geophysics ◽  
2021 ◽  
pp. 1-56
Author(s):  
Flavio Poletto ◽  
Alex Goertz ◽  
Cinzia Bellezza ◽  
Endre Vange Bergfjord ◽  
Piero Corubolo ◽  
...  
Keyword(s):  
Barents Sea ◽  
Seismic Profile ◽  
Microseismic Monitoring ◽  
Drill String ◽  
Drill Bit ◽  
Ocean Bottom ◽  
Vertical Seismic Profile ◽  
Data Set ◽  
Typical Application ◽  
Drilling Rig

Seismic while drilling (SWD) by drill-bit source has been successfully used in the past decades and is proven using variable configurations in onshore applications. The method creates a reverse vertical seismic profile (RVSP) dataset from surface sensors deployed as arrays in the proximity of the monitored wells. The typical application makes use of rig-pilot reference (pilot) sensors at the top of the drill-string and also downhole. This approach provides while-drilling checkshots as well as multioffset RVSP for 2-D and 3-D imaging around the well and prediction ahead of the bit. For logistical (sensor deployment) and cost (rig time related to technical installation) reasons the conventional drill-bit SWD application is typically much easier onshore than offshore. We present a novel approach that uses a network of passive-monitoring sea bottom nodes pre-deployed for microseismic monitoring to simultaneously and effectively record offshore SWD data. We study the results of a pilot test where we passively monitored the drilling of an appraisal well at the Wisting discovery in the Barents Sea with an ocean-bottom cable deployed temporarily around the drilling rig. The continuous passive recording of vibration signals emitted during the drilling of the well provides the SWD data set, which is treated as a reverse vertical seismic profile. The study is performed without rig-pilot signal. The results are compared with legacy data and demonstrate the effectiveness of the approach and point to future applications for real-time monitoring of the drilling progress, both in terms of geosteering the drill bit and predicting formation properties ahead of the bit by reflection imaging.

A proposed polarity standard for multicomponent seismic data

Geophysics ◽  
2002 ◽  
Vol 67 (4) ◽  
pp. 1028-1037 ◽  
Author(s):  
R. James Brown ◽  
Robert R. Stewart ◽  
Don C. Lawton
Keyword(s):  
Ground Motion ◽  
Pressure Change ◽  
Seismic Profile ◽  
Primary Objective ◽  
Data Sets ◽  
Ocean Bottom ◽  
Data Set ◽  
Field Recording ◽  
Sea Bottom ◽  
Cable Lines

This paper proposes a multicomponent acquisition and preprocessing polarity standard that will apply generally to the three Cartesian geophone components and the hydrophone or microphone components of a 2‐D or 3‐D multicomponent survey on land, at the sea bottom, acquired as a vertical seismic profile, vertical‐cable, or marine streamer survey. We use a four‐component ocean‐bottom data set for purposes of illustration and example. A primary objective is a consistent system of polarity specifications to facilitate consistent horizon correlation among multicomponent data sets and enable determination of correct reflectivity polarity. The basis of this standard is the current SEG polarity standard, first enunciated as a field‐recording standard for vertical geophone data and hydrophone streamer data. It is founded on a right‐handed coordinate system: z positive downward; x positive in the forward line direction in a 2‐D survey, or a specified direction in a 3‐D survey, usually that of the receiver‐cable lines; and y positive in the direction 90° clockwise from x. The polarities of these axes determine the polarity of ground motion in any component direction (e.g., downward ground motion recording as positive values on the vertical‐geophone trace). According also to this SEG standard, a pressure decrease is to be recorded as positive output on the hydrophone trace. We also recommend a cyclic indexing convention, [W, X, Y, Z] or [0, 1, 2, 3], to denote hydrophone or microphone (pressure), inline (radial) geophone, crossline (transverse) geophone, and vertical geophone, respectively. We distinguish among three kinds of polarity standard: acquisition, preprocessing, and final‐display standards. The acquisition standard (summarized in the preceding paragraph) relates instrument output solely to sense of ground motion (geophones) and of pressure change (hydrophones). Polarity considerations beyond this [involving, e.g., source type, wave type (P or S), direction of arrival, anisotropy, tap‐test adjustments, etc.] fall under preprocessing polarity standards. We largely defer any consideration of a display standard.

Integrated prestack depth migration of vertical seismic profile and surface seismic data from the Rocky Mountain Foothills of southern Alberta, Canada

Geophysics ◽  
2003 ◽  
Vol 68 (6) ◽  
pp. 1782-1791 ◽  
Author(s):  
M. Graziella Kirtland Grech ◽  
Don C. Lawton ◽  
Scott Cheadle
Keyword(s):  
Seismic Data ◽  
Rocky Mountain ◽  
Velocity Model ◽  
Seismic Profile ◽  
Vertical Seismic Profile ◽  
Prestack Depth Migration ◽  
Data Set ◽  
Depth Migration ◽  
Southern Alberta ◽  
Vsp Data

We have developed an anisotropic prestack depth migration code that can migrate either vertical seismic profile (VSP) or surface seismic data. We use this migration code in a new method for integrated VSP and surface seismic depth imaging. Instead of splicing the VSP image into the section derived from surface seismic data, we use the same migration algorithm and a single velocity model to migrate both data sets to a common output grid. We then scale and sum the two images to yield one integrated depth‐migrated section. After testing this method on synthetic surface seismic and VSP data, we applied it to field data from a 2D surface seismic line and a multioffset VSP from the Rocky Mountain Foothills of southern Alberta, Canada. Our results show that the resulting integrated image exhibits significant improvement over that obtained from (a) the migration of either data set alone or (b) the conventional splicing approach. The integrated image uses the broader frequency bandwidth of the VSP data to provide higher vertical resolution than the migration of the surface seismic data. The integrated image also shows enhanced structural detail, since no part of the surface seismic section is eliminated, and good event continuity through the use of a single migration–velocity model, obtained by an integrated interpretation of borehole and surface seismic data. This enhanced migrated image enabled us to perform a more robust interpretation with good well ties.

Anisotropic frequency-dependent spreading of seismic waves from first-arrival vertical seismic profile data analysis

Geophysics ◽  
2013 ◽  
Vol 78 (6) ◽  
pp. C41-C52 ◽  
Author(s):  
Amin Baharvand Ahmadi ◽  
Igor Morozov
Keyword(s):  
Seismic Waves ◽  
Seismic Profile ◽  
Anisotropic Scattering ◽  
Profile Data ◽  
Vertical Seismic Profile ◽  
Data Set ◽  
Frequency Dependent ◽  
Geometric Spreading ◽  
First Arrival ◽  
Viscoelastic Modeling

A model of first-arrival amplitude decay combining geometric spreading, scattering, and inelastic dissipation is derived from a multioffset, 3D vertical seismic profile data set. Unlike the traditional approaches, the model is formulated in terms of path integrals over the rays and without relying on the quality factor ([Formula: see text]) for rocks. The inversion reveals variations of geometric attenuation (wavefront curvatures and scattering, [Formula: see text]) and the effective attenuation parameter ([Formula: see text]) with depth. Both of these properties are also found to be anisotropic. Scattering and geometric spreading (focusing and defocusing) significantly affect seismic amplitudes at lower frequencies and shallower depths. Statistical analysis of model uncertainties quantitatively measures the significance of these results. The model correctly predicts the observed frequency-dependent first-arrival amplitudes at all frequencies. This and similar models can be applied to other types of waves and should be useful for true-amplitude studies, including inversion, inverse [Formula: see text]-filtering, and amplitude variations with offset analysis. With further development of petrophysical models of internal friction and elastic scattering, attenuation parameters [Formula: see text] and [Formula: see text] should lead to constraints on local heterogeneity and intrinsic physical properties of the rock. These parameters can also be used to build models of the traditional frequency-dependent [Formula: see text] for forward and inverse numerical viscoelastic modeling.

Walk‐away VSP using drill noise as a source

Geophysics ◽  
1995 ◽  
Vol 60 (4) ◽  
pp. 978-997 ◽  
Author(s):  
Jacob B. U. Haldorsen ◽  
Douglas E. Miller ◽  
John J. Walsh
Keyword(s):  
Seismic Profile ◽  
Drill String ◽  
Seismic Survey ◽  
Effective Bandwidth ◽  
Walk Away ◽  
Data Set ◽  
Deconvolution Technique ◽  
Noise Data ◽  
Zero Offset ◽  
Noise Signature

We describe a method for extracting and deconvolving a signal generated by a drill bit and collected by an array of surface geophones. The drill‐noise signature is reduced to an effective impulse by means of a multichannel Wiener deconvolution technique, producing a walk‐away reverse vertical seismic profile (VSP) sampled almost continuously in depth. We show how the multichannel technique accounts for noise and for internal drill‐string reflections, automatically limiting the deconvolved data to frequencies containing significant energy. We have acquired and processed a data set from a well in Germany while drilling at a depth of almost 4000 m. The subsurface image derived from these data compares well with corresponding images from a 3-D surface seismic survey, a zero‐offset VSP survey, and a walk‐away VSP survey acquired using conventional wireline techniques. The effective bandwidth of the deconvolved drill‐noise data is comparable to the bandwidth of surface seismic data but significantly smaller than what can be achieved with wireline VSP techniques. Although the processing algorithm does not require the use of sensors mounted on the drill string, these sensors provide a very economic way to compress the data. The sensors on the drill string were also used for accurate timing of the deconvolved drill‐noise data.

Seismic interferometry with a TBM source of transmitted and reflected waves

Geophysics ◽  
2006 ◽  
Vol 71 (4) ◽  
pp. SI85-SI93 ◽  
Author(s):  
Flavio Poletto ◽  
Lorenzo Petronio
Keyword(s):  
Tunnel Boring Machine ◽  
Seismic Profile ◽  
Drill Bit ◽  
Seismic Profiles ◽  
Amplitude Analysis ◽  
Tunnel Face ◽  
Data Set ◽  
Reflected Waves ◽  
The Waves ◽  
Reversed Time

We discuss the use of autocorrelogram interferometry by using noise from the tunnel-boring machine (TBM). The TBM provides seismic signals/waves while drilling in a tunnel (TSWD). The tunnel geometry, unlike a reverse vertical seismic profile (RVSP) using a drill bit, makes it possible to record the waves reflected from the region between the tunnel face and the projected tunnel exit and those transmitted ahead of the tunnel face. We processed the waves recorded at back positions with respect to the TBM in a manner similar to a RVSP data set obtained by conventional reference-correlation techniques. We processed the waves transmitted ahead of the TBM using autocorrelogram interferometry techniques. Using these wavefields offers advantages over conventional borehole drill-bit vertical seismic profiles (VSPs). The most important advantage is getting reflections from the transmitted (front) wavefield by utilizing Kunetz’s equation and reversed-time traces. The approach also improves the analysis of the transmitted amplitudes. Finally, we improved the deconvolution of the reflected (back) waves by using the transmitted wavefields measured for interferometry purposes. In particular, by using both front (transmitted) and back (reflected) waves, it is possible to deconvolve the signature of the source extended spatially along the tunnel axis. We use a 1D model in which the interfaces are assumed subvertical. We present a case history in which TSWD data were acquired in a tunnel measuring [Formula: see text] long. We compare results from the transmitted reversed-time and back-reflected waves ([Formula: see text]-waves) with those obtained by amplitude analysis and estimation of reflection coefficients. Each approach matches the interpretation of the fractures encountered in the tunnel.

Crosscorrelogram migration of inverse vertical seismic profile data

Geophysics ◽  
2006 ◽  
Vol 71 (1) ◽  
pp. S1-S11 ◽  
Author(s):  
Jianhua Yu ◽  
Gerard T. Schuster
Keyword(s):  
Seismic Profile ◽  
Source Location ◽  
Horizontal Resolution ◽  
Drill Bit ◽  
Interferometric Imaging ◽  
Profile Data ◽  
Coherent Noise ◽  
Vertical Seismic Profile ◽  
Kirchhoff Migration ◽  
Reflector Geometry

We present the theory of crosscorrelogram migration of ghost reflections, also known as interferometric imaging, to delineate reflector geometries from inverse vertical seismic profile data. The theory includes the equations for forward modeling, migration, asymptotic inversion, and model resolution of crosscorrelgrams. Rather than using primary reflections, crosscorrelogram migration can use ghost reflections to reconstruct the reflector geometry. Other multiples can be used as well, including pegleg multiples and higher-order multiples. Its main advantages over conventional Kirchhoff migration are (1) both source location (e.g., drill-bit position) and source wavelet need not be known (such as when using a drill bit as a source in a deviated well), (2) it is insensitive to source-related static errors, and (3) it has wider subsurface illumination than conventional Kirchhoff migration of primary reflections. Crosscorrelation migration can effectively widen the source-receiver aperture by more than 50% compared to standard inverse vertical seismic profile (IVSP) migration. The primary disadvantages are (1) it uses ghost reflections for imaging, which can be weaker (or sometimes more distorted) than primary reflections; (2) crosscorrelation creates virtual multiples that can sometimes appear as coherent noise in the final image; and (3) it has poorer horizontal resolution than standard IVSP migration. Results from imaging simulated IVSP traces show that crosscorrelation migration produces reflectivity-like images that correlate well with the actual reflector geometry of a layered fault model. These images are almost completely immune to static errors at the source location and have wider subsurface illumination than conventional IVSP migration images. We also apply crosscorrelation migration to IVSP data recorded at a Friendswood, Texas, test site. Results show that the crosscorrelation image correlates better with the well log and wider subsurface illumination than a conventional Kirchhoff migration image.

Local migration with extrapolated VSP Green’s functions

Geophysics ◽  
2009 ◽  
Vol 74 (1) ◽  
pp. SI15-SI26 ◽  
Author(s):  
Xiang Xiao ◽  
Gerard T. Schuster
Keyword(s):  
Velocity Model ◽  
Seismic Profile ◽  
Imaging Method ◽  
Local Velocity ◽  
Dynamic Effects ◽  
Vertical Seismic Profile ◽  
Data Set ◽  
Numerical Tests ◽  
Vsp Data ◽  
Backward Propagation

We have developed a novel vertical seismic profile (VSP) imaging method that requires only a local velocity model around the well. This method is denoted as a “local migration,” where the model-based forward-propagation and backward-propagation operators are computed using a local velocity model between the well and the target body. The velocity model for the complex overburden and salt body is not needed, and the source-side statics are automatically accounted for. In addition, kinematic and dynamic effects, including anisotropy, absorption, and other unknown/undefined rock effects outside of this local velocity model, are mostly accounted for. Numerical tests on an acoustic 2D Sigsbee VSP data set, an elastic salt model, and offset 2D VSP data in the Gulf of Mexico partly validate the effectiveness of this method by accurately imaging the sediments next to the vertical well.

scholarly journals Elastic full-waveform inversion of vertical seismic profile data acquired with distributed acoustic sensors

Geophysics ◽  
2018 ◽  
Vol 83 (3) ◽  
pp. R273-R281 ◽  
Author(s):  
Anton Egorov ◽  
Julia Correa ◽  
Andrej Bóna ◽  
Roman Pevzner ◽  
Konstantin Tertyshnikov ◽  
...  
Keyword(s):  
Elastic Properties ◽  
Particle Velocity ◽  
Waveform Inversion ◽  
Vertical Component ◽  
Seismic Profile ◽  
Full Waveform Inversion ◽  
Vertical Seismic Profile ◽  
Data Set ◽  
Full Waveform ◽  
Vsp Data

Distributed acoustic sensing (DAS) is a rapidly developing technology particularly useful for the acquisition of vertical seismic profile (VSP) surveys. DAS data are increasingly used for seismic imaging, but not for estimating rock properties. We have developed a workflow for estimating elastic properties of the subsurface using full-waveform inversion (FWI) of DAS VSP data. Whereas conventional borehole geophones usually measure three components of particle velocity, DAS measures a single quantity, which is an approximation of the strain or strain rate along the fiber. Standard FWI algorithms are developed for particle velocity data, and hence their application to DAS data requires conversion of these data to particle velocity along the fiber. This conversion can be accomplished by a specially designed filter. Field measurements show that the conversion result is close to vertical particle velocity as measured by geophones. Elastic time-domain FWI of a synthetic multioffset VSP data set for a vertical well shows that the inversion of the vertical component alone is sufficient to recover elastic properties of the subsurface. Application of the proposed workflow to a multioffset DAS data set acquired at the CO2CRC Otway Project site in Victoria, Australia, reveals salient subhorizontal layering consistent with the known geology of the site. The inverted [Formula: see text] model at the well location matches the upscaled [Formula: see text] log with a correlation coefficient of 0.85.

Traveltime inversion of both direct and reflected arrivals in vertical seismic profile data

Geophysics ◽  
1989 ◽  
Vol 54 (1) ◽  
pp. 49-56 ◽  
Author(s):  
Edward L. Salo ◽  
Gerard T. Schuster
Keyword(s):  
Least Squares ◽  
Velocity Structure ◽  
Seismic Profile ◽  
Profile Data ◽  
Vertical Seismic Profile ◽  
Data Set ◽  
Traveltime Inversion ◽  
Sonic Log ◽  
Vsp Data

Traveltimes from both direct and reflected arrivals in a VSP data set (Bridenstein no. 1 well in Oklahoma) are inverted in a least‐squares sense for velocity structure. By comparing the structure from inversion to the sonic log, we conclude that the accuracy of the reconstructed velocities is greater than that found when only the direct arrivals are used. Extensive tests on synthetic VSP data confirm this observation. Apparently, the additional reflection traveltime equations aid in averaging out the traveltime errors, as well as reducing the slowness variance in reflecting layers. These results are consistent with theory, which predicts a decrease in a layer’s slowness variance with an increase in the number and length of terminating reflected rays. For the Bridenstein data set, 130 direct traveltimes and 399 primary reflection traveltimes were used in the inversion.

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