Q estimation from vertical seismic profile data and anomalous variations in the central North Sea

Geophysics ◽  
1985 ◽  
Vol 50 (4) ◽  
pp. 615-626 ◽  
Author(s):  
S. D. Stainsby ◽  
M. H. Worthington
Keyword(s):  
North Sea ◽  
Pulse Width ◽  
Spectral Ratio ◽  
Seismic Profile ◽  
Seismic Attenuation ◽  
Recording Equipment ◽  
Vertical Seismic Profile ◽  
High Attenuation ◽  
Vsp Data ◽  
Central North Sea

Four different methods of estimating Q from vertical seismic profile (VSP) data based on measurements of spectral ratios, pulse amplitude, pulse width, and zeroth lag autocorrelation of the attenuated impulse are described. The last procedure is referred to as the pulse‐power method. Practical problems concerning nonlinearity in the estimating procedures, uncertainties in the gain setting of the recording equipment, and the influence of structure are considered in detail. VSP data recorded in a well in the central North Sea were processed to obtain estimates of seismic attenuation. These data revealed a zone of high attenuation from approximately 4 900 ft to [Formula: see text] ft with a value of [Formula: see text] Results of the spectral‐ratio analysis show that the data conform to a linear constant Q model. In addition, since the pulse‐width measurement is dependent upon the dispersive model adopted, it is shown that a nondispersive model cannot possibly provide a match to the real data. No unambiguous evidence is presented that explains the cause of this low Q zone. However, it is tentatively concluded that the seismic attenuation may be associated with the degree of compaction of the sediments and the presence of deabsorbed gases.

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.

Specular interferometric imaging of vertical seismic profile data

2015 ◽  
Vol 3 (3) ◽  
pp. SW57-SW62 ◽  
Author(s):  
Yunsong Huang ◽  
Ruiqing He ◽  
Chaiwoot Boonyasiriwat ◽  
Yi Luo ◽  
Gerard Schuster
Keyword(s):  
Ray Tracing ◽  
Field Data ◽  
Seismic Profile ◽  
The Other ◽  
Interferometric Imaging ◽  
Profile Data ◽  
Vertical Seismic Profile ◽  
Ghost Image ◽  
Primary Image ◽  
Vsp Data

We introduce the concept of seminatural migration of multiples in vertical seismic profile (VSP) data, denoted as specular interferometric migration, in which part of the kernel is computed by ray tracing and the other part is obtained from the data. It has the advantage over standard migration of ghost reflections, in that the well statics are eliminated and the migration image is no more sensitive to velocity errors than migration of VSP primaries. Moreover, the VSP ghost image has significantly more subsurface illumination than the VSP primary image. The synthetic and field data results validate the effectiveness of this method.

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.

Antialiasing condition and filter for the reciprocity equation of correlation type

Geophysics ◽  
2010 ◽  
Vol 75 (6) ◽  
pp. WB219-WB224 ◽  
Author(s):  
Weiping Cao ◽  
Gerard T. Schuster
Keyword(s):  
Seismic Data ◽  
Seismic Profile ◽  
Numerical Results ◽  
Numerical Implementation ◽  
Vertical Seismic Profile ◽  
Vsp Data ◽  
And Migration

An antialiasing formula has been derived for interferometric redatuming of seismic data. More generally, this formula is valid for numerical implementation of the reciprocity equation of correlation type, which is used for redatuming, extrapolation, interpolation, and migration. The antialiasing condition can be, surprisingly, more tolerant of a coarser trace sampling compared to the standard antialiasing condition. Numerical results with synthetic vertical seismic profile (VSP) data show that interferometry artifacts are effectively reduced when the antialiasing condition is used as a constraint with interferometric redatuming.

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 Subsalt Depth Imaging Using 3-D VSP Technique in the Ras El Ush Field, Gulf of Suez, Egypt

GeoArabia ◽  
1999 ◽  
Vol 4 (3) ◽  
pp. 363-378
Author(s):  
Mohammed A. Badri ◽  
Taha M. Taha ◽  
Robert W. Wiley
Keyword(s):  
Seismic Data ◽  
Seismic Profile ◽  
Poor Quality ◽  
Gulf Of Suez ◽  
Geological Model ◽  
Vertical Seismic Profile ◽  
Depth Imaging ◽  
Vsp Data ◽  
Basement High ◽  
Definition Of

ABSTRACT In 1995 oil was discovered in the pre-Miocene Matulla and Nubia Sandstones in the Ras El Ush field, Gulf of Suez, Egypt. The discovery was based on an aeromagnetic anomaly from a basement high. After drilling several delineation wells, based on a geological model, it became evident that the field is very complex as it is broken into tilted and rotated compartmental blocks by two perpendicular fault systems. Also the 2-D seismic data were of poor quality beneath the thick Miocene South Gharib Evaporite. Since part of the field lies below shallow-water, 3-D seismic was considered to be too costly. When a delineation well did not encounter the reservoir, due to an unanticipated fault, a 2-D walkaway Vertical Seismic Profile (VSP) was acquired. It clearly revealed the presence of a cross fault. The success of the 2-D VSP in imaging the fault led to the acquisition of the first Middle East 3-D VSP survey in the following well. A downhole, tri-axial, five geophone array tool was used to acquire the 3-D VSP. The 3-D volume of the final migrated VSP data provided the means for the reliable mapping of horizons beneath the South Gharib Evaporite. These maps improved the definition of the field and helped detect previously unrecognized prospective blocks. Four further successful delineation wells confirmed the 3-D VSP interpretation.

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.

An integrated surface seismic/seismic profile case study: Simonette area, Alberta

Geophysics ◽  
1993 ◽  
Vol 58 (11) ◽  
pp. 1676-1688
Author(s):  
Ronald C. Hinds ◽  
Neil L. Anderson ◽  
Richard Kuzmiski
Keyword(s):  
Seismic Data ◽  
Cost Effective ◽  
Seismic Profile ◽  
Viable Alternative ◽  
Target Area ◽  
Vertical Seismic Profile ◽  
Subsurface Geology ◽  
Well Location ◽  
Vsp Data

On the basis of conventional surface seismic data, the 13–15–63–25W5M exploratory well was drilled into a low‐relief Leduc Formation reef (Devonian Woodbend Group) in the Simonette area, west‐central Alberta, Canada. The well was expected to intersect the crest of the reef and encounter about 50–60 m of pay; unfortunately it was drilled into a flank position and abandoned. The decision to abandon the well, as opposed to whipstocking in the direction of the reef crest, was made after the acquisition and interpretive processing of both near( and far‐offset (252 and 524 m, respectively) vertical seismic profile (VSP) data, and after the reanalysis of existing surface seismic data. The near‐ and far‐offset VSPs were run and interpreted while the drill rig remained on‐site, with the immediate objectives of: (1) determining an accurate tie between the surface seismic data and the subsurface geology; and (2) mapping relief along the top of the reef over a distance of 150 m from the 13–15 well location in the direction of the adjacent productive 16–16 well (with a view to whipstocking). These surveys proved to be cost‐effective in that the operators were able to determine that the crest of the reef was out of the target area, and that whipstocking was not a viable alternative. The use of VSP surveys in this situation allowed the operators to avoid the costs associated with whipstocking, and to feel confident with their decision to abandon the well.

SV-P extraction and imaging for far-offset vertical seismic profile data

2015 ◽  
Vol 3 (3) ◽  
pp. SW27-SW35 ◽  
Author(s):  
Yandong Li ◽  
Bob A. Hardage
Keyword(s):  
Ray Tracing ◽  
Marcellus Shale ◽  
Seismic Profile ◽  
P Wave ◽  
Time Varying ◽  
Profile Data ◽  
Vertical Seismic Profile ◽  
Optimal Receiver ◽  
Common Depth Point ◽  
Vsp Data

We have analyzed vertical seismic profile (VSP) data acquired across a Marcellus Shale prospect and found that SV-P reflections could be extracted from far-offset VSP data generated by a vertical-vibrator source using time-variant receiver rotations. Optimal receiver rotation angles were determined by a dynamic steering of geophones to the time-varying approach directions of upgoing SV-P reflections. These SV-P reflections were then imaged using a VSP common-depth-point transformation based on ray tracing. Comparisons of our SV-P image with P-P and P-SV images derived from the same offset VSP data found that for deep targets, SV-P data created an image that extended farther from the receiver well than P-P and P-SV images and that spanned a wider offset range than P-P and P-SV images do. A comparison of our VSP SV-P image with a surface-based P-SV profile that traversed the VSP well demonstrated that SV-P data were equivalent to P-SV data for characterizing geology and that a VSP-derived SV-P image could be used to calibrate surface-recorded SV-P data that were generated by P-wave sources.

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.

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