Imaging improvements from subsalt 3D VSP acquisitions in the Gulf of Mexico

2019 ◽  
Vol 38 (11) ◽  
pp. 865-871 ◽  
Author(s):  
Jean-Paul van Gestel ◽  
Ken Hartman ◽  
Corey Joy ◽  
Qingsong Li ◽  
Michael Pfister ◽  
...  
Keyword(s):  
Gulf Of Mexico ◽  
Seismic Data ◽  
Large Scale ◽  
Survey Design ◽  
Seismic Profile ◽  
Lessons Learned ◽  
Data Sets ◽  
High Quality ◽  
Business Decisions ◽  
Vsp Data

From 2015 through 2018, BP acquired six large-scale 3D vertical seismic profile (VSP) data sets at their Gulf of Mexico assets, two at each of the Thunder Horse, Mad Dog, and Atlantis fields. The acquisition of these large-scale data sets was enabled by the development of a 100-level wireline tool and the adoption of simultaneous shooting. With those two developments, it became feasible to acquire data sets with the coverage and data density needed to build high-quality images of the subsurface using 3D VSP acquisitions. There have been recent advances in finite difference modeling to guide the survey design and the high-quality processing that is required to create the 3D VSP image volumes. These volumes have two main advantages over conventional surface seismic data. First, in 3D VSP acquisition, the receiver can be located below the overlying salt bodies, which allows for illumination of the reservoirs that cannot be achieved using surface seismic data. Second, the location of the receivers closer to the imaging targets enables higher frequency content of the resulting VSP data compared to conventional surface seismic images. Both imaging enhancements can have a significant business value, and the resulting VSP data sets have demonstrated a clear impact on business decisions. In the three case studies, we demonstrate the business impact of the 3D VSP data acquired through improvement of imaging of stratigraphic edges, improved interpretation of fault geometry and orientation, and related improvement of the quality of well planning and targeting. We conclude with discussion on cost, global impact, and present recommendations and lessons learned for future surveys.

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.

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.

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.

Seismic stratigraphic relationships within a lowstand reservoir system: examples from the Barrow Group, Southern Exmouth Sub-Basin, NW Australia

2014 ◽  
Vol 54 (2) ◽  
pp. 1 ◽  
Author(s):  
Gerry O’Halloran ◽  
Chris Hurren ◽  
Tim O’Hara
Keyword(s):  
Seismic Data ◽  
Late Stage ◽  
Data Sets ◽  
High Quality ◽  
Seismic Control ◽  
Karoo Basin ◽  
Depositional Processes ◽  
Shelf Slope ◽  
Basin Floor ◽  
Surrounding Areas

The Late Jurassic–Early Cretaceous Eskdale and Macedon members of the lower Barrow Group comprise some of the main oil-bearing reservoirs in the Exmouth Sub-basin. These high quality sandstones form the reservoirs in the Stybarrow and Eskdale oil fields. Understanding the architecture of these deepwater successions is important in both exploration and development projects. This paper documents detailed stratigraphic relationships and depositional geometries as defined on high quality seismic data sets and associated well data. An initial phase of lowstand deposition (Eskdale Member) is recorded by the development of two main canyon systems; the Eskdale and slightly younger Laverda canyons. These systems are remarkably well imaged on 3D seismic data, allowing for detailed definition of channel morphology and associated fill and spill facies. Channel complexes are up to 1 km-wide and 100 m-deep, and display evidence for multiple phases of erosion and in-channel aggradation. Overbank/spill facies are also identifiable, including crevasse lateral lobes and ‘chute’ channels. These canyon systems fed contemporaneous downdip basin floor fans that display a variety of classical fan morphologies and depositional elements including terminal lobes, fan pinchout edges, distributary channel systems and localised outflow facies. The distribution and morphology of the Eskdale and Laverda canyons and associated fan intervals can be related to topographic gradient changes within the basin (i.e. from shelf to slope to basin floor). These topographic changes are in turn a response to regional tectonism, in particular active rifting along basin margins. An ensuing phase of less confined, shelf-slope turbidite deposition (Macedon Member) records late-stage lowstand processes. Detailed well and seismic control from the Stybarrow Field and surrounding areas has identified multicyclic sands recording deposition of stacked turbidite lobes. These lobe complexes are more laterally continuous than the canyon facies and are comprised of amalgamated sheet sands and lower-relief channel sands, and are generally between 15–25 m thick. In the greater Stybarrow area the original lobate geometries have been subsequently modified by a phase of late-stage erosion. Outcrop analogues for the Macedon Member can be seen in the lobe complexes from the Tanqua Fan intervals of the Karoo Basin, which are similar in both scale and morphology. These lobe complexes extend laterally for tens of kilometres with constituent individual lobes often displaying evidence for compensational depositional processes. This paper was originally published in the Proceedings of the West Australian Basins Symposium 2013, which was held from 18–21 August 2013 in Perth, Australia.

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.

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.

scholarly journals Rifted margins classification and forcing parameters

2021 ◽  
Vol 11 (1) ◽  
Author(s):  
F. Sapin ◽  
J.-C. Ringenbach ◽  
C. Clerc
Keyword(s):  
Mechanical Behavior ◽  
Seismic Data ◽  
Large Scale ◽  
Oceanic Lithosphere ◽  
Continental Lithosphere ◽  
Mechanical Behaviors ◽  
High Quality ◽  
Rifted Margins ◽  
Simple Classification ◽  
Exhaustive List

AbstractRifted margins are the result of the successful process of thinning and breakup of the continental lithosphere leading to the formation of new oceanic lithosphere. Observations on rifted margins are now integrating an increasing amount of multi-channel seismic data and drilling of several Continent-Ocean Transitions. Based on large scale geometries and domains observed on high-quality multi-channel seismic data, this article proposes a classification reflecting the mechanical behavior of the crust from localized to diffuse deformation (strong/coupled to weak/decoupled mechanical behaviors) and magmatic intensity leading to breakup from magma-rich to magma-poor margins. We illustrate a simple classification based on mechanical behavior and magmatic production with examples of rifted margins. We propose a non-exhaustive list of forcing parameters that can control the initial rifting conditions but also their evolution through time. Therefore, rifted margins are not divided into opposing types, but described as a combination and continuum that can evolve through time and space.

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