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

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.

Download Full-text

Time-lapse walkaway vertical seismic profile monitoring for CO2 injection at the SACROC enhanced oil recovery field: A case study

Geophysics ◽

10.1190/geo2013-0274.1 ◽

2014 ◽

Vol 79 (2) ◽

pp. B51-B61 ◽

Cited By ~ 13

Author(s):

Di Yang ◽

Alison Malcolm ◽

Michael Fehler ◽

Lianjie Huang

Keyword(s):

Enhanced Oil Recovery ◽

Oil Recovery ◽

Time Lapse ◽

Seismic Profile ◽

Vertical Seismic Profile ◽

Image Domain ◽

Velocity Models ◽

Injection Zone ◽

Vsp Data ◽

Velocity Changes

Geologic carbon storage involves large-scale injections of carbon dioxide into underground geologic formations. Changes in reservoir properties resulting from [Formula: see text] injection and migration can be characterized using monitoring methods with time-lapse seismic data. To achieve economical monitoring, vertical seismic profile (VSP) data are often acquired to survey the local injection area. We investigated the capability of walkaway VSP monitoring for [Formula: see text] injection into an enhanced oil recovery field at SACROC, West Texas. VSP data sets were acquired in 2008 and 2009, and [Formula: see text] injection took place after the first data acquisition. Because the receivers were located above the injection zone, only reflection data contain the information from the reservoir. Qualitative comparison between reverse-time migration images at different times revealed vertical shifts of the reflectors’ center, indicating the presence of velocity changes. We examined two methods to quantify the changes in velocity: standard full-waveform inversion (FWI) and image-domain wavefield tomography (IDWT). FWI directly inverts seismic waveforms for velocity models. IDWT inverts for the time-lapse velocity changes by matching the baseline and time-lapse migration images. We found that, for the constrained geometry of VSP surveys, the IDWT result was significantly more consistent with a localized change in velocity as expected from a few months of [Formula: see text] injection. A synthetic example was used to verify the result from the field data. By contrast, FWI failed to provide quantitative information about the volumetric velocity changes because of the survey geometry and data frequency content.

Download Full-text

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

Interpretation ◽

10.1190/int-2014-0248.1 ◽

2015 ◽

Vol 3 (3) ◽

pp. SW11-SW25 ◽

Cited By ~ 22

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.

Download Full-text

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

Geophysics ◽

10.1190/1.1441937 ◽

1985 ◽

Vol 50 (4) ◽

pp. 615-626 ◽

Cited By ~ 54

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.

Download Full-text

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

Geophysics ◽

10.1190/1.1635031 ◽

2003 ◽

Vol 68 (6) ◽

pp. 1782-1791 ◽

Cited By ~ 1

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.

Download Full-text

Specular interferometric imaging of vertical seismic profile data

Interpretation ◽

10.1190/int-2014-0251.1 ◽

2015 ◽

Vol 3 (3) ◽

pp. SW57-SW62 ◽

Cited By ~ 3

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.

Download Full-text

PRACTICAL USE OF BOREHOLE SEISMIC IN EXPLORATION

The APPEA Journal ◽

10.1071/aj83034 ◽

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.

Download Full-text

Antialiasing condition and filter for the reciprocity equation of correlation type

Geophysics ◽

10.1190/1.3495542 ◽

2010 ◽

Vol 75 (6) ◽

pp. WB219-WB224 ◽

Cited By ~ 1

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.

Download Full-text

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

Geophysics ◽

10.1190/geo2020-0155.1 ◽

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.

Download Full-text