3D wave-equation interferometric migration of VSP free-surface multiples

Geophysics ◽  
2007 ◽  
Vol 72 (5) ◽  
pp. S195-S203 ◽  
Author(s):  
Ruiqing He ◽  
Brian Hornby ◽  
Gerard Schuster
Keyword(s):  
Wave Equation ◽  
Free Surface ◽  
Signal To Noise Ratio ◽  
Time Lapse ◽  
Seismic Profile ◽  
Velocity Estimation ◽  
Seismic Survey ◽  
3D Surface ◽  
Vsp Data ◽  
Image Volume

Interferometric migration of free-surface multiples in vertical-seismic-profile (VSP) data has two significant advantages over standard VSP imaging: (1) a significantly larger imaging area compared to migrating VSP primaries and (2) less sensitivity to velocity-estimation and static errors than other methods for migration of multiples. In this paper, we present a 3D wave-equation interferometric migration method that efficiently images VSP free-surface multiples. Synthetic and field data results confirm that a reflectivity image volume, comparable in size to a 3D surface seismic survey around the well, can be computed economically. The reflectivity image volume has less fold density and lower signal-to-noise ratio than that obtained by a conventional 3D surface seismic survey because of the relatively weak energy of multiples and the limited number of geophones in the well. However, the efficiency of this method for migrating VSP multiples suggests that it might sometimes be a useful tool for 4D seismic monitoring where reflectivity images can be computed quickly for each time-lapse survey.

scholarly journals Interface-targeted seismic velocity estimation using machine learning

2019 ◽  
Vol 218 (1) ◽  
pp. 45-56 ◽  
Author(s):  
C Nur Schuba ◽  
Jonathan P Schuba ◽  
Gary G Gray ◽  
Richard G Davy
Keyword(s):  
Neural Network ◽  
Regression Model ◽  
Dimensional Space ◽  
Seismic Profile ◽  
Velocity Estimation ◽  
Seismic Survey ◽  
Wide Angle ◽  
Seismic Velocities ◽  
Lower Dimensional Space ◽  
Lower Dimensional

SUMMARY We present a new approach to estimate 3-D seismic velocities along a target interface. This approach uses an artificial neural network trained with user-supplied geological and geophysical input features derived from both a 3-D seismic reflection volume and a 2-D wide-angle seismic profile that were acquired from the Galicia margin, offshore Spain. The S-reflector detachment fault was selected as the interface of interest. The neural network in the form of a multilayer perceptron was employed with an autoencoder and a regression layer. The autoencoder was trained using a set of input features from the 3-D reflection volume. This set of features included the reflection amplitude and instantaneous frequency at the interface of interest, time-thicknesses of overlying major layers and ratios of major layer time-thicknesses to the total time-depth of the interface. The regression model was trained to estimate the seismic velocities of the crystalline basement and mantle from these features. The ‘true’ velocities were obtained from an independent full-waveform inversion along a 2-D wide-angle seismic profile, contained within the 3-D data set. The autoencoder compressed the vector of inputs into a lower dimensional space, then the regression layer was trained in the lower dimensional space to estimate velocities above and below the targeted interface. This model was trained on 50 networks with different initializations. A total of 37 networks reached minimum achievable error of 2 per cent. The low standard deviation (<300  m s−1) between different networks and low errors on velocity estimations demonstrate that the input features were sufficient to capture variations in the velocity above and below the targeted S-reflector. This regression model was then applied to the 3-D reflection volume where velocities were predicted over an area of ∼400 km2. This approach provides an alternative way to obtain velocities across a 3-D seismic survey from a deep non-reflective lithology (e.g. upper mantle) , where conventional reflection velocity estimations can be unreliable.

PRACTICAL USE OF BOREHOLE SEISMIC IN EXPLORATION

1984 ◽  
Vol 24 (1) ◽  
pp. 429
Author(s):  
F. Sandnes W. L. Nutt ◽  
S. G. Henry
Keyword(s):  
Seismic Data ◽  
Seismic Profile ◽  
Seismic Survey ◽  
Vertical Seismic Profile ◽  
Direct Signal ◽  
Seismic Fault ◽  
Time Calibration ◽  
Vsp Data ◽  
Borehole Seismic ◽  
Processing Techniques

The improvement of acquisition and processing techniques has made it possible to study seismic wavetrains in boreholes.With careful acquisition procedures and quantitative data processing, one can extract useful information on the propagation of seismic events through the earth, on generation of multiples and on the different reflections coming from horizons that may not all be accessible by surface seismic.An extensive borehole seismic survey was conducted in a well in Conoco's contract area 'Block B' in the South China Sea. Shots at 96 levels were recorded, and the resulting Vertical Seismic Profile (VSP) was carefully processed and analyzed together with the Synthetic Seismogram (Geogram*) and the Synthetic Vertical Seismic Profile (Synthetic VSP).In addition to the general interpretation of the VSP data, i.e. time calibration of surface seismic, fault identification, VSP trace inversion and VSP Direct Signal Analysis, the practical inclusion of VSP data in the reprocessing of surface seismic data was studied. Conclusions that can be drawn are that deconvolution of surface seismic data using VSP data must be carefully approached and that VSP can be successfully used to examine phase relationships in seismic data.

Vertical seismic profile migration using the Kirchhoff integral

Geophysics ◽  
1988 ◽  
Vol 53 (6) ◽  
pp. 786-799 ◽  
Author(s):  
P. B. Dillon
Keyword(s):  
Wave Equation ◽  
Wave Field ◽  
Near Field ◽  
Synthetic Data ◽  
Real Data ◽  
Seismic Profile ◽  
Processing Strategies ◽  
Receiver Array ◽  
Vsp Data ◽  
Kirchhoff Integral

Wave‐equation migration can form an accurate image of the subsurface from suitable VSP data. The image’s extent and resolution are determined by the receiver array dimensions and the source location(s). Experiments with synthetic and real data show that the region of reliable image extent is defined by the specular “zone of illumination.” Migration is achieved through wave‐field extrapolation, subject to an imaging procedure. Wave‐field extrapolation is based upon the scalar wave equation and, for VSP data, is conveniently handled by the Kirchhoff integral. The migration of VSP data calls for imaging very close to the borehole, as well as imaging in the far field. This dual requirement is met by retaining the near‐field term of the integral. The complete integral solution is readily controlled by various weighting devices and processing strategies, whose worth is demonstrated on real and synthetic data.

Quantifying hydraulically induced fracture height and density from rapid time-lapse DAS VSP

Geophysics ◽  
2020 ◽  
pp. 1-26
Author(s):  
Xiaomin Zhao ◽  
Mark E. Willis ◽  
Tanya Inks ◽  
Glenn A. Wilson
Keyword(s):  
Rock Physics ◽  
Horizontal Wells ◽  
Time Lapse ◽  
Seismic Profile ◽  
P Wave ◽  
Fracture Properties ◽  
Vsp Data ◽  
Rock Physics Modeling ◽  
Physics Modeling ◽  
Fracture Height

Several recent studies have advanced the use of time-lapse distributed acoustic sensing (DAS) vertical seismic profile (VSP) data in horizontal wells for determining hydraulically stimulated fracture properties. Hydraulic fracturing in a horizontal well typically generates vertical fractures in the rock medium around each stage. We model the hydraulically stimulated formation with vertical fracture sets about the lateral wellbore as a horizontally transverse isotropic (HTI) medium. Rock physics modeling is used to relate the anisotropy parameters to fracture properties. This modeling was used to develop an inversion for P-wave time delay to fracture height and density of each stage. Field data from two horizontal wells were analyzed, and fracture height evaluated using this technique agreed with microseismic analysis.

Measurement of seawater average velocity using water bottom multiples from vertical seismic profile surveys

2016 ◽  
Vol 4 (4) ◽  
pp. SQ13-SQ22 ◽  
Author(s):  
Yingping Li ◽  
Ben Hewett
Keyword(s):  
Average Velocity ◽  
Seismic Velocity ◽  
Autonomous Underwater Vehicles ◽  
Time Lapse ◽  
Seismic Profile ◽  
Temporal Variations ◽  
Vertical Seismic Profile ◽  
Velocity Models ◽  
Vsp Data ◽  
Water Bottom

Previous diagnoses of surface seismic velocity models with vertical seismic profile (VSP) data in the Gulf of Mexico have indicated that shallow velocities were poorly constrained by VSP due to ringing caused by multiple casing strings. This ringing also hampered direct measurement of the seawater average velocity (SWAV) at a rig site with direct arrivals of a zero-offset VSP (ZVSP). We have directly measured the SWAV at a rig site with a known water depth by using differential times between primary water bottom multiples (WBMs) and direct first arrivals acquired in a marine VSP survey. We developed a procedure to process ZVSP-WBM signals for SWAV measurement. This WBM method is successfully applied to VSP data recorded at 27 rig sites in the deep-water environments of North and South America. Our results suggest that VSP processors should implement this method and add the SWAV measurement in their future velocity survey reports. We have estimated water bottom depths using differential times. We found that the estimated water depths are comparable with those acquired from sonar measurements by autonomous underwater vehicles, but with large uncertainties. The WBM method is extended by using data from a vertical incidence VSP to measure a profile of the SWAV along the path of a deviated well and evaluate possible lateral variations of SWAV. This method can potentially be applied to a time-lapse VSP to monitor temporal variations of SWAV. We also evaluated the application scope and limitations of the WBM method.

scholarly journals 3D vertical seismic profile acquired with distributed acoustic sensing on tubing installation: A case study from the CO2CRC Otway Project

2019 ◽  
Vol 7 (1) ◽  
pp. SA11-SA19 ◽  
Author(s):  
Julia Correa ◽  
Roman Pevzner ◽  
Andrej Bona ◽  
Konstantin Tertyshnikov ◽  
Barry Freifeld ◽  
...  
Keyword(s):  
Fiber Length ◽  
Fiber Optic ◽  
Signal To Noise Ratio ◽  
Seismic Profile ◽  
Lessons Learned ◽  
Vertical Seismic Profile ◽  
Acoustic Sensing ◽  
Vsp Data ◽  
Distributed Acoustic Sensing

Distributed acoustic sensing (DAS) can revolutionize the seismic industry by using fiber-optic cables installed permanently to acquire on-demand vertical seismic profile (VSP) data at fine spatial sampling. With this, DAS can solve some of the issues associated with conventional seismic sensors. Studies have successfully demonstrated the use of DAS on cemented fibers for monitoring applications; however, such applications on tubing-deployed fibers are relatively uncommon. Application of tubing-deployed fibers is especially useful for preexisting wells, where there is no opportunity to install a fiber behind the casing. In the CO2CRC Otway Project, we acquired a 3D DAS VSP using a standard fiber-optic cable installed on the production tubing of the injector well. We aim to analyze the quality of the 3D DAS VSP on tubing, as well as discuss lessons learned from the current DAS deployment. We find the limitations associated with the DAS on tubing, as well as ways to improve the quality of the data sets for future surveys at Otway. Due to the reduced coupling and the long fiber length (approximately 20 km), the raw DAS records indicate a high level of noise relative to the signal. Despite the limitations, the migrated 3D DAS VSP data recorded by cable installed on tubing are able to image interfaces beyond the injection depth. Furthermore, we determine that the signal-to-noise ratio might be improved by reducing the fiber length.

Time-lapse wave-equation migration velocity analysis

Geophysics ◽  
2013 ◽  
Vol 78 (2) ◽  
pp. S69-S79 ◽  
Author(s):  
Jeffrey Shragge ◽  
David Lumley
Keyword(s):  
Wave Equation ◽  
Time Lapse ◽  
Migration Velocity ◽  
Velocity Estimation ◽  
Earth Model ◽  
Linear Perturbation ◽  
Velocity Analysis ◽  
Approximate Methods ◽  
Migration Velocity Analysis ◽  
Image Difference

Time-lapse (4D) analysis of seismic data acquired at different stages of hydrocarbon production or gas/fluid injection has been very successful at imaging detailed reservoir changes. Conventional time-domain analysis of 4D data sets usually assumes a linear perturbation about a reference baseline earth model. However, this assumption is violated when production/injection significantly alters the subsurface generating large 4D velocity changes, time shifts, and complicated 4D wavefield coda, necessitating a more robust 4D analysis involving prestack wave-equation depth migration and velocity analysis. We address these situations by extending conventional 3D wave-equation migration velocity analysis (WEMVA) based on one-way wave-equations and single-scattering theory to 4D velocity estimation using a “parallel” inversion approach involving parallel solution of two separate inversion problems. Recognizing that the 4D WEMVA strategy requires precomputed baseline/monitor image-difference volumes, we develop an approximate 4D WEMVA technique that replaces these differences with a single weight function derived from the smooth background time-lapse image difference. We demonstrate the usefulness of the parallel and an approximate 4D WEMVA approach using a synthetic time-lapse [Formula: see text] geosequestration experiment that requires inverting for a thin-layer velocity change derived from [Formula: see text] injection in an analogue North Sea reservoir. The parallel 4D WEMVA solutions generate an excellent high-resolution velocity estimates, whereas the approximate methods recover lower-resolution estimates with magnitudes that must be rescaled through a post-inversion gradient line-search.

Dual-well 3D vertical seismic profile enabled by distributed acoustic sensing in deepwater Gulf of Mexico

2015 ◽  
Vol 3 (3) ◽  
pp. SW11-SW25 ◽  
Author(s):  
Han Wu ◽  
Wai-Fan Wong ◽  
Zhaohui Yang ◽  
Peter B. Wills ◽  
Jorge L. Lopez ◽  
...  
Keyword(s):  
Gulf Of Mexico ◽  
Velocity Model ◽  
Seismic Profile ◽  
Seismic Survey ◽  
Vertical Seismic Profile ◽  
Acoustic Sensing ◽  
Velocity Models ◽  
Vsp Data ◽  
Distributed Acoustic Sensing

We have acquired and processed 3D vertical seismic profile (VSP) data recorded simultaneously in two wells using distributed acoustic sensing (DAS) during the acquisition of the 2012 Mars 4D ocean-bottom seismic survey in the deepwater Gulf of Mexico. The objectives of the project were to assess the quality of DAS data recorded in fiber-optic cables from the surface to the total depth, to demonstrate the efficacy of the DAS VSP technology in a deepwater environment, to derisk the use of the technology for future water injection or production monitoring without intervention, and to exploit the velocity information that 3D VSP data provide for evaluating and updating the velocity model. We evaluated the advantages of DAS VSP to reduce costs and intrusiveness, and we determined that high-quality images can be obtained from relatively noisy raw 3D DAS VSP data, as evidenced by the well 1 image, probably the best 3D VSP image we have ever seen. Our results also revealed that the direct arrival traveltimes can be used to assess the quality of an existing velocity model and to invert for an improved velocity model. We identified issues with the DAS acquisition and the processing steps to mitigate them and to handle problems specific to DAS VSP data. We described the steps for conditioning the data before migration, reverse time migration, and postmigration processing to reduce noise artifacts. We outlined a novel first-break picking procedure that works even in the absence of a strong first arrival and a velocity diagnosis method to assess and validate velocity models and velocity updates. Finally, we determined potential applications to 4D monitoring of fluid movement around producer or injector wells, identification of active salt movements, and more accurate imaging and monitoring of complex structures around the wells.

Tomographic modeling of a cross‐borehole data set

Geophysics ◽  
1989 ◽  
Vol 54 (10) ◽  
pp. 1249-1257 ◽  
Author(s):  
Larry R. Lines ◽  
Edward D. LaFehr
Keyword(s):  
Wave Equation ◽  
Ray Tracing ◽  
Velocity Model ◽  
Velocity Estimation ◽  
P Wave ◽  
Seismic Survey ◽  
Equation Modeling ◽  
Data Set ◽  
True Solution ◽  
Velocity Models

In this paper we describe a methodology for estimating P‐wave velocities from a cross‐borehole seismic survey that uses straight‐ray tomography, ray tracing, and finite‐difference wave‐equation modeling to produce velocity models that fit the first‐break traveltimes. After a starting model is established by straight‐ray tomography, the velocity model is checked by ray tracing and wave‐equation modeling. Since the models for each procedure show consistent results and the modeled traveltimes closely match those traveltimes from the actual data, we felt our interpretation was confirmed. However, the fitting of cross‐well first break traveltimes is only a necessary validity check and is not sufficient to guarantee that the true solution has been found. Two wells were drilled through the areas that were anomalous on the derived tomogram and check‐shot velocity surveys were run. Due primarily to a lateral ambiguity in velocity estimation caused by too few near‐vertical raypaths, the check‐shot surveys did not agree with the tomogram velocities. However, subsequently the check‐shot traveltimes were used to place bounds on velocity in a constrained least‐squares procedure; the combined modeling of uphole and cross‐well rays produced an optimum velocity model which satisfies all available data.

Imaging the Aquistore reservoir after 36 kilotonnes of CO2 injection using distributed acoustic sensing

Geophysics ◽  
2017 ◽  
Vol 82 (6) ◽  
pp. M81-M96 ◽  
Author(s):  
Kyle Harris ◽  
Don White ◽  
Claire Samson
Keyword(s):  
Time Lapse ◽  
Seismic Survey ◽  
Co2 Injection ◽  
Baseline Survey ◽  
Acoustic Sensing ◽  
Monitoring Wells ◽  
Amplitude Anomaly ◽  
Vsp Data ◽  
Distributed Acoustic Sensing ◽  
Saline Formation

Aquistore is a geologic [Formula: see text] storage project that is using a deep saline formation as a storage reservoir. From April 2015 to February 2016, approximately 36 kilotonnes of [Formula: see text] were injected into the reservoir at a depth of 3130–3350 m. We have developed an analysis of distributed acoustic sensing (DAS) 3D vertical seismic profiling data acquired in February 2016, marking the first seismic survey since injection began. The VSP data were processed in parallel with baseline preinjection data from a November 2013 survey, with the objective of detecting and characterizing the subsurface [Formula: see text] plume and evaluating the repeatability of DAS in a reservoir monitoring project. A single processing sequence was devised that (1) accurately imaged the reservoir for the baseline and monitor data and (2) attained adequate repeatability to observe time-lapse differences related to the presence of [Formula: see text]. Repeatability was somewhat compromised by the less advanced noise cancellation methodology of the DAS system used for the baseline survey. In the final cross-equalized migrated data volumes, normalized root-mean-square ([Formula: see text]rms) difference values of [Formula: see text] were attained at the reservoir level indicating good repeatability compared with most surface seismic studies. An injection-related amplitude anomaly with maximum [Formula: see text]rms values of approximately 0.7 is apparent in the Deadwood Formation of the reservoir, whereas no significant [Formula: see text]rms anomalies were observed near the injection and monitoring wells in the Black Island Member or above the reservoir.

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