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DAS 3D VSP imaging and potential applications

Posted by Cullen Young

Natural gas hydrates have been identified  by the Department of Energy (DOE) as both a potential energy source as well as a potential significant contributor to global climate change, making them an important and exciting topic to research. One of the fundamental objectives for improving hydrate production models and our understanding of the associated climate risk is to develop computational geophysical techniques that combine three-dimensional (3-D) seismic data with borehole observations to obtain a more complete geological characterization of gas hydrate systems. Detailed analysis of distributed acoustic sensing 3-D vertical seismic profile (DAS 3-D VSP ) data promises to provide high-resolution seismic images of reservoir characteristics away from boreholes, as well as insights into the distribution and properties of gas hydrate units. To take full advantage of the information content offered by cutting-edge DAS 3-D VSP technology, though, requires developing improved quantitative and high-resolution seismic imaging and inversion approaches capable of generating the data products required for enabling high-resolution reservoir characterization.

Figure 1: 2-D slice oriented in the azimuth of the deviated well extracted from 3-D acoustic RTM image volume with the VP well log shown in blue. The depth of four main interfaces inferred from log data are shown to the right of the image: the D1 and B1 sand unit tops and the bases of ice-bearing permafrost (BIBPF) and significant ice-bearing permafrost (BSIBPF). The inset map shows the source locations (blue dots), the well trajectory (black line) and the 2-D slice orientation (green line).


I use a DAS 3-D VSP field data set from a test well near Prudhoe Bay on the Alaskan North Slope to develop a 3-D seismic imaging framework. This expands on previous research focused on developing a DAS 3-D VSP seismic imaging framework that improves the quality of existing 3-D imaging results by developing and validating an alternative data processing workflow, a 3-D velocity tomography analysis, high-resolution 3-D acoustic reverse-time migration (RTM), and well-tie validation (see Figure 1).

Figure 2: Illustration of the difference between (a) E-RTM and (b) E-LSRTM imaging results. Through the RTM technique, image reflectors can be observed in (a), however, it suffers from artifacts and unbalanced amplitudes. Using the E-LSRTM technique (b), the same reflectors are image but with better balanced amplitudes and reduced artifacts. Example from Tugrul Konuk’s work on elastic LSRTM (Konuk 2020).

My previous research showed that applying acoustic 3-D RTM imaging to a DAS 3-D VSP data set can provide significant added value to gas hydrates projects and suggests that applying more advanced seismic inversion approaches such as elastic LSRTM and FWI could recover higher-resolution and fully quantitative estimates of subsurface reflectivity. Figure 2 shows an example from Tugrul Konuk’s work on elastic LSRTM (Konuk 2020), and the improvements in image resolution that can be aquired when using LSRTM techniques. The quantitative information from the produced images, specifically geological structure, will be useful to better understand the stability and temporal evolution of gas hydrate systems, and for advancing the overall understanding of the environmental and socioeconomic risks associated with gas-hydrate-related natural and human-induced geologic hazards. Extending beyond gas hydrate systems, the developed computational imaging and inversion framework can be potentially used to better understand CO2 geosequestration and geothermal activities as well as other subsurface monitoring applications.

The graphics on this page were generated by Derrick Chambers using the AI Generator Midjourney.


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