IDENTIFICATION OF GAS HYDRATES AND BOTTOM SIMULATING REFLECTORS IN FAR OFFSET SEISMIC IMAGES

2021 ◽  
pp. 1-60
Author(s):  
Darrell A. Terry ◽  
Camelia C. Knapp
Keyword(s):  
Gas Hydrates ◽  
Seismic Data ◽  
Single Channel ◽  
Seismic Analysis ◽  
Cost Effective ◽  
Ocean Bottom ◽  
Bottom Simulating Reflector ◽  
Avo Analysis ◽  
Bottom Simulating Reflectors ◽  
Seismic Images

The presence of marine gas hydrates is routinely inferred based on the identification of bottom simulating reflectors (BSRs) in common depth-point (CDP) seismic images. Additional seismic studies such as amplitude variation with offset (AVO) analysis can be applied for corroboration. Though confirmation is needed by drilling and sampling, seismic analysis has proven to be a cost-effective approach to identify the presence of marine gas hydrates. Single channel far offset seismic images are investigated for what appears to be a more reliable and cost-effective indicator for the presence of bottom simulating reflectors than traditional CDP processing or AVO analysis. A non-traditional approach to processing seismic data is taken to be more relevant to imaging the gas/gas hydrate contact. Instead of applying the traditional CDP seismic processing workflows from the oil industry, we more carefully review the significant amount of information existing in the data to explore how the character of the data changes as offset angle increases. Three cases from different environments are selected for detailed analysis. These include 1) stratigraphy running parallel with the ocean bottom; 2) a potential bottom simulating reflector, running parallel to the ocean bottom, and cross-cutting dipping reflections, and 3) a suspected thermal intrusion without a recognizable bottom simulating reflector. This investigation considers recently collected multi-channel seismic data from the deep waters of the central Aleutian Basin beneath the Bering Sea, the pre-processing of the data sets, and the methodology for processing and display to generate single channel seismic images. Descriptions are provided for the single channel near and far offset seismic images for the example cases. Results indicate that BSRs related to marine gas hydrates, and originating due to the presence of free gas, are more easily and uniquely identifiable from single channel displays of far offset seismic images than from traditional CDP displays.

Estimation of gas hydrate and free gas saturation, concentration, and distribution from seismic data

Geophysics ◽  
2002 ◽  
Vol 67 (2) ◽  
pp. 582-593 ◽  
Author(s):  
Shaoming Lu ◽  
George A. McMechan
Keyword(s):  
Gas Hydrate ◽  
Seismic Data ◽  
Acoustic Impedance ◽  
Single Channel ◽  
Pore Space ◽  
Theoretical Models ◽  
Free Gas ◽  
Bottom Simulating Reflector ◽  
Saturation Concentration ◽  
Empirical Relations

Gas hydrates contain a major untapped source of energy and are of potential economic importance. The theoretical models to estimate gas hydrate saturation from seismic data predict significantly different acoustic/elastic properties of sediments containing gas hydrate; we do not know which to use. Thus, we develop a new approach based on empirical relations. The water‐filled porosity is calibrated (using well‐log data) to acoustic impedance twice: one calibration where gas hydrate is present and the other where free gas is present. The water‐filled porosity is used in a combination of Archie equations (with corresponding parameters for either gas hydrate or free gas) to estimate gas hydrate or free gas saturations. The method is applied to single‐channel seismic data and well logs from Ocean Drilling Program leg 164 from the Blake Ridge area off the east coast of North America. The gas hydrate above the bottom simulating reflector (BSR) is estimated to occupy ∼3–8% of the pore space (∼2–6% by volume). Free gas is interpreted to be present in three main layers beneath the BSR, with average gas saturations of 11–14%, 7–11%, and 1–5% of the pore space (6–8%, 4–6%, and 1–3% by volume), respectively. The estimated saturations of gas hydrate are very similar to those estimated from vertical seismic profile data and generally agree with those from independent, indirect estimates obtained from resistivity and chloride measurements. The estimated free gas saturations agree with measurements from a pressure core sampler. These results suggest that locally derived empirical relations between porosity and acoustic impedance can provide cost‐effective estimates of the saturation, concentration, and distribution of gas hydrate and free gas away from control wells.

Inpainting of local wavefront attributes using artificial intelligence for enhancement of massive 3-D pre-stack seismic data

2020 ◽  
Vol 223 (3) ◽  
pp. 1888-1898
Author(s):  
Kirill Gadylshin ◽  
Ilya Silvestrov ◽  
Andrey Bakulin
Keyword(s):  
Artificial Intelligence ◽  
Seismic Data ◽  
Cost Effective ◽  
Computational Effort ◽  
Full Density ◽  
Ocean Bottom ◽  
Data Set ◽  
Marine Seismic ◽  
Missing Attributes

SUMMARY We propose an advanced version of non-linear beamforming assisted by artificial intelligence (NLBF-AI) that includes additional steps of encoding and interpolating of wavefront attributes using inpainting with deep neural network (DNN). Inpainting can efficiently and accurately fill the holes in waveform attributes caused by acquisition geometry gaps and data quality issues. Inpainting with DNN delivers excellent quality of interpolation with the negligible computational effort and performs particularly well for a challenging case of irregular holes where other interpolation methods struggle. Since conventional brute-force attribute estimation is very costly, we can further intentionally create additional holes or masks to restrict expensive conventional estimation to a smaller subvolume and obtain missing attributes with cost-effective inpainting. Using a marine seismic data set with ocean bottom nodes, we show that inpainting can reliably recover wavefront attributes even with masked areas reaching 50–75 per cent. We validate the quality of the results by comparing attributes and enhanced data from NLBF-AI and conventional NLBF using full-density data without decimation.

The influence of volcanic rocks on the characterization of Rosebank Field – new insights from ocean-bottom seismic data and geological analogues integrated through interpretation and modelling

2016 ◽  
Vol 8 (1) ◽  
pp. 373-384 ◽  
Author(s):  
S. Poppitt ◽  
L. J. Duncan ◽  
B. Preu ◽  
F. Fazzari ◽  
J. Archer
Keyword(s):  
Seismic Data ◽  
Reservoir Characterization ◽  
Seismic Analysis ◽  
Volcanic Rocks ◽  
Flood Basalt ◽  
Ocean Bottom ◽  
Volcanic System ◽  
Field Development ◽  
Velocity Models ◽  
Depth Prediction

AbstractDuring Late Paleocene–Early Eocene times, the modern Rosebank structure was located at the juxtaposition of the easterly advancing Flett volcanic system and the northerly prograding Flett delta. As a result, the Rosebank reservoir sandstones are interstratified with volcanic and volcaniclastic rocks, offering challenges for reservoir imaging, depth prediction and reservoir characterization. These challenges have driven the application of Ocean Bottom Node (OBN) seismic technology. OBN data have yielded improved velocity models for depth conversion, better reservoir definition and key insights to aid the modelling of sand distribution from seismic attributes. Spectral decomposition of the OBN seismic data has facilitated the extraction of distinct volcanic subunits, whilst spectral enhancement has enabled visualization of complex stacking patterns within individual igneous layers. To complement the seismic analysis, detailed geological analogue studies have been undertaken in volcanic provinces such as the Palaeogene volcanic district of SE Greenland and the Columbia River Flood Basalt Province, USA. No single outcrop provides a definitive analogy to Rosebank, but each offers insights that provide an important link to understanding and managing the main subsurface uncertainties associated with field development. Integration of these multiple workflows have improved the reservoir characterization and provided the foundation for the optimization of the field development plan.

Heat Flow Calculation Based on Seismic Data

2014 ◽  
Vol 915-916 ◽  
pp. 1202-1206
Author(s):  
Rui Yang ◽  
Neng You Wu ◽  
Yuan Yuan ◽  
Ming Su ◽  
Shao Hua Qiao ◽  
...  
Keyword(s):  
Heat Flow ◽  
Gas Hydrates ◽  
Seismic Data ◽  
Reliable Method ◽  
Three Dimensional ◽  
Flow Calculation ◽  
Bottom Simulating Reflectors ◽  
Main Factors ◽  
Hydrate Stability

Heat flow calculation is a reliable method to estimate the vibration about temperature, main factors of the existence of marine gas hydrates below seafloor. It would increase the accuracy of resources volume estimating and reduce cost of exploration significantly. Depth of Bottom Simulating Reflectors (BSRs), known as the base of gas hydrate stability zone (GHSZ), is a critical variable in this calculation. It should be recognized and mapped using the good quality three-dimensional (3D) pre-stack migration seismic data. By introducing heat flow derived from the depths of BSRs, this method would improve the resolution of the profiles and the quality of imaging and can be used in the specific areas.

Application of complex-trace analysis to seismic data for random-noise suppression and temporal resolution improvement

Geophysics ◽  
2006 ◽  
Vol 71 (3) ◽  
pp. V79-V86 ◽  
Author(s):  
Hakan Karsli ◽  
Derman Dondurur ◽  
Günay Çifçi
Keyword(s):  
Seismic Data ◽  
Trace Analysis ◽  
Noise Suppression ◽  
Single Channel ◽  
Random Noise ◽  
Synthetic Data ◽  
Low Frequency ◽  
Bright Spot ◽  
Phase Information ◽  
Resolution Improvement

Time-dependent amplitude and phase information of stacked seismic data are processed independently using complex trace analysis in order to facilitate interpretation by improving resolution and decreasing random noise. We represent seismic traces using their envelopes and instantaneous phases obtained by the Hilbert transform. The proposed method reduces the amplitudes of the low-frequency components of the envelope, while preserving the phase information. Several tests are performed in order to investigate the behavior of the present method for resolution improvement and noise suppression. Applications on both 1D and 2D synthetic data show that the method is capable of reducing the amplitudes and temporal widths of the side lobes of the input wavelets, and hence, the spectral bandwidth of the input seismic data is enhanced, resulting in an improvement in the signal-to-noise ratio. The bright-spot anomalies observed on the stacked sections become clearer because the output seismic traces have a simplified appearance allowing an easier data interpretation. We recommend applying this simple signal processing for signal enhancement prior to interpretation, especially for single channel and low-fold seismic data.

Downward and upward continuation of 2-D seismic data to eliminate ocean bottom topography’s effect

2010 ◽  
Vol 7 (2) ◽  
pp. 149-157 ◽  
Author(s):  
Xiang-Chun Wang ◽  
Chang-Liang Xia ◽  
Xue-Wei Liu
Keyword(s):  
Seismic Data ◽  
Ocean Bottom ◽  
Upward Continuation

Acquire Ocean Bottom Seismic Data and Time-Lapse Geochemistry Data Simultaneously to Identify Compartmentalization and Map Hydrocarbon Movement

2021 ◽  
Author(s):  
Rick Schrynemeeckers
Keyword(s):  
High Resolution ◽  
Seismic Data ◽  
Time Lapse ◽  
Field Trials ◽  
Detection Methods ◽  
Ocean Bottom ◽  
Field Development ◽  
Dense Grid ◽  
Hydrocarbon Charge ◽  
Sweet Spots

Abstract Current offshore hydrocarbon detection methods employ vessels to collect cores along transects over structures defined by seismic imaging which are then analyzed by standard geochemical methods. Due to the cost of core collection, the sample density over these structures is often insufficient to map hydrocarbon accumulation boundaries. Traditional offshore geochemical methods cannot define reservoir sweet spots (i.e. areas of enhanced porosity, pressure, or net pay thickness) or measure light oil or gas condensate in the C7 – C15 carbon range. Thus, conventional geochemical methods are limited in their ability to help optimize offshore field development production. The capability to attach ultrasensitive geochemical modules to Ocean Bottom Seismic (OBS) nodes provides a new capability to the industry which allows these modules to be deployed in very dense grid patterns that provide extensive coverage both on structure and off structure. Thus, both high resolution seismic data and high-resolution hydrocarbon data can be captured simultaneously. Field trials were performed in offshore Ghana. The trial was not intended to duplicate normal field operations, but rather provide a pilot study to assess the viability of passive hydrocarbon modules to function properly in real world conditions in deep waters at elevated pressures. Water depth for the pilot survey ranged from 1500 – 1700 meters. Positive thermogenic signatures were detected in the Gabon samples. A baseline (i.e. non-thermogenic) signature was also detected. The results indicated the positive signatures were thermogenic and could easily be differentiated from baseline or non-thermogenic signatures. The ability to deploy geochemical modules with OBS nodes for reoccurring surveys in repetitive locations provides the ability to map the movement of hydrocarbons over time as well as discern depletion affects (i.e. time lapse geochemistry). The combined technologies will also be able to: Identify compartmentalization, maximize production and profitability by mapping reservoir sweet spots (i.e. areas of higher porosity, pressure, & hydrocarbon richness), rank prospects, reduce risk by identifying poor prospectivity areas, accurately map hydrocarbon charge in pre-salt sequences, augment seismic data in highly thrusted and faulted areas.

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