Enhancing subsalt imaging through advanced identification and suppression of interbed multiples and mode-converted reflections — Gulf of Mexico and Brazil case studies

In our case studies, the success of subsalt exploration and development wells depended heavily on the characterization of highly heterogeneous lacustrine microbial carbonates. Acoustic and elastic inversions have proved to be a good proxy for identification of reservoir quality variation for exploration and development well placements. However, qualitative and quantitative usage of subsalt seismic amplitudes requires proper illumination and good signal-to-noise ratio. If properly imaged, mode-converted reflections and interbed multiples can be complementary to the P-wave image. But, in conventional P-wave-oriented imaging, both types of events cannot be imaged correctly. They appear as coherent noise and negatively impact the overall exploration and development project outcomes, especially in areas with poor illumination. This paper consists of two parts: first, we investigate the potential problems resulting from converted waves and interbed multiples in data from two different basins — the Gulf of Mexico and the Campos Basin in offshore Brazil — and show our approach to attenuate them to reveal the true structures. The second part focuses on advanced identification of interbed multiples in modeling and migration methods. To facilitate the various strategies to attenuate interbed multiples, “interpretation” of the various events plays a significant role. Vertical seismic profile (VSP) data are excellent for the purpose; however, these data are only available at well locations, if they are recorded. As a result of many years of technology advancement, pseudo VSP data can be constructed effectively from standard streamer survey data. Two methods are highlighted in this paper for building pseudo VSP data in a full two-way sense, based on a typical Brazil-type salt model: Marchenko-based processing and full-wavefield migration. Major subsalt plays in the Gulf of Mexico and emerging plays in Brazil should benefit significantly from elimination of these kinds of coherent noise.

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Physical Properties and Structure of the Near Subsurface in the Săcel Area, Romania, from Shallow Seismic Measurements

Journal of Environmental and Engineering Geophysics ◽

10.2113/jeeg24.1.151 ◽

2019 ◽

Vol 24 (1) ◽

pp. 151-158

Author(s):

Ionelia Panea

Keyword(s):

Wave Velocity ◽

Signal To Noise Ratio ◽

Soil Surface ◽

Geological Structure ◽

P Wave ◽

S Wave ◽

Sedimentary Deposits ◽

Shallow Seismic ◽

P Wave Velocity ◽

Good Signal

Results are presented for shallow seismic reflection measurements performed southwest of Săcel village in Romania for the purpose of obtaining information about the geological structure in the near subsurface. The P-wave and S-wave velocity distributions were also obtained below the soil surface. The measurements were performed along a nearly linear profile on the top of an elongated hill. Most of the shot gathers were characterized by a good signal-to-noise ratio. A depth-converted migrated section was obtained after the processing of shot gathers, on which an image of sedimentary deposits with various thicknesses, separated by shallow faults until a depth of about 80 m, were observed. The P-wave and S-wave velocity-depth models for two segments were of considerable interest for a geotechnical study proposed for the construction of a windmill park. The two- and three-layered P-wave velocity-depth models were comparable until depths of about 10 m after first-arrival traveltime inversions. The lateral variations in the subsurface geological structure and lithology reflected the variations in the P-wave velocity values from both models. The S-wave velocity-depth models for comparable depth intervals were similar to those from the P-wave velocity-depth models. Reliable S-wave velocity distributions were obtained after inversion of fundamental-mode and higher-mode surface waves.

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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.

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

Interpretation ◽

10.1190/int-2018-0086.1 ◽

2019 ◽

Vol 7 (1) ◽

pp. SA11-SA19 ◽

Cited By ~ 1

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.

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

Geophysics ◽

10.1190/1.2743375 ◽

2007 ◽

Vol 72 (5) ◽

pp. S195-S203 ◽

Cited By ~ 36

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.

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

Interpretation ◽

10.1190/int-2015-0002.1 ◽

2015 ◽

Vol 3 (3) ◽

pp. SW27-SW35 ◽

Cited By ~ 11

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.

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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.

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P- and S-wave characterization of near‐surface reflectivity from glacial tills using vertical seismic profiles

Geophysics ◽

10.1190/1.1444606 ◽

1999 ◽

Vol 64 (3) ◽

pp. 970-980 ◽

Cited By ~ 5

Author(s):

Bradley J. Carr ◽

Zoltan Hajnal

Keyword(s):

Wave Energy ◽

Acoustic Property ◽

Seismic Profile ◽

P Wave ◽

S Wave ◽

Glacial Deposits ◽

Near Surface ◽

Borehole Geophysics ◽

Vsp Data

Fundamental reflectivity properties are established within the glacial deposits of central Saskatchewan, Canada. Multicomponent vertical seismic profile (VSP) data collected in three shallow boreholes are used to obtain detailed acoustic property information within the first 80 m of the near‐surface strata. The integration of both P- and S-wave VSP data, in conjunction with other borehole geophysics, provided a unique opportunity to obtain in‐situ seismic reflection response properties in layered clay and sand tills. P- and S-wave interval velocity profiles, in conjunction with P- and S-wave VSP reflectivities are analyzed to provide insight into seismic wavefield behavior within ∼80 m of the surface. In general, shear wave energy identifies more reflective intervals than the P-wave energy because of better vertical resolution for S-wave energy (0.75 m) compared to P-wave energy (2.3 m) based on quarter wavelength criterion. For these saturated, unconsolidated glacial deposits, more details about the lithologic constituents and in‐situ porosity are detectable from the S-wave reflectivity, but P-wave reflections provide a good technique for mapping the bulk changes. The principal cause of seismic reflectivity is the presence and/or amount of sand, and the degree of fluid‐filled porosity within the investigated formations.

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Two methods for determining geophone orientations from VSP data

Geophysics ◽

10.1190/1.2208935 ◽

2006 ◽

Vol 71 (4) ◽

pp. V87-V97 ◽

Cited By ~ 25

Author(s):

Xiaoxian Zeng ◽

George A. McMechan

Keyword(s):

A Priori ◽

Polarization Plane ◽

Seismic Profile ◽

P Wave ◽

Earth Model ◽

S Wave ◽

Coherent Signals ◽

Plane Method ◽

Wave Separation ◽

Vsp Data

Vertical seismic profile (VSP) data are usually acquired with three-component geophones of unknown azimuthal orientation. The geophone orientation must be estimated from the recorded data as a prerequisite to processing such as P- and S-wave separation, calculation of wave-incident directions, and 3D migration. We compare and combine two methods for estimating azimuthal orientation by least-squares fitting over a large number of shots. Combining the two methods can be done in an automated manner, which provides more accurate estimates of the geophone orientations than previous methods. In the polarization-plane method, we calculate the polarization plane of the first P-wave arrival. Then we subtract the source azimuth to determine the geophone orientation, independently for each geophone, with an angular uncertainty of [Formula: see text], and with no accumulated errors. In the relative-angle method, we obtain relative angles between adjacent geophone pairs using trace crosscorrelations, and operate on all coherent signals (even noise). Swapped geophone components can be detected automatically using the polarization-plane method. The main limitation of these (and all other known) methods is that uncertainties associated with path refraction are not estimated, unless some geophones have a priori known orientations, or we have a known earth model to correct for refraction.

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

The Leading Edge ◽

10.1190/tle38110865.1 ◽

2019 ◽

Vol 38 (11) ◽

pp. 865-871 ◽

Cited By ~ 2

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.

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Multicomponent VSP imaging of tight-gas sands

Geophysics ◽

10.1190/1.2335646 ◽

2006 ◽

Vol 71 (6) ◽

pp. E83-E90 ◽

Cited By ~ 2

Author(s):

John O’Brien ◽

Ron Harris

Keyword(s):

Shear Wave ◽

Negative Impact ◽

Mode Conversion ◽

Strong Support ◽

Seismic Profile ◽

Limited Range ◽

P Wave ◽

Wave Source ◽

Cotton Valley ◽

Vsp Data

Low-porosity Bossier and Cotton Valley sands of the East Texas Basin, U. S., have only a small acoustic impedance contrast with the encasing shales but a greater relative contrast in shear-wave impedance. Vertical seismic profile (VSP) data acquired with both a near-offset and far-offset P-wave source clearly demonstrate the P-P reflectivity and P-S mode conversions within the Bossier section. We designate conventional P-wave reflectivity as P-P, shear-wave reflectivity as S-S, and P-wave/shear-wave mode conversion data as P-S. While Bossier P-P reflectivity is low, it appears to be adequate for mapping thick sandbodies such as the York Sandstone, the main exploration target in this area. However, P-P reflectivity is even lower and is inadequate for imaging the overlying Cotton Valley Sands. In contrast, the far-offset VSP data acquired with a P-wave source demonstrate a high level of P-S-mode conversion, which is used to image this interval with definition that is not provided by P-P reflectivity. This provides strong support for the use of P-S-mode conversion imaging for seismic characterization of tight sand reservoirs. Near-offset shear-wave VSP data acquired with a shearwave source show low S/N ratio and limited bandwidth for the downgoing waveform because of the depth of the target; shear-wave energy appears to have a more limited range of propagation than P-waves. Such effects may also have a strong negative impact on multicomponent imaging of these sands using surface seismic techniques. Multicomponent 3D VSP imaging provides a superior solution by placing the geophones closer to the subsurface zone of interest.

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