Rock formation characterization for CO2‐EOR and carbon geosequestration; 3D seismic amplitude and coherency anomalies, Wellington Field, Kansas, USA

Between 1973 and 1996 West Australian Petroleum Pty Limited (WAPET) discovered five major gas fields on the southern Rankin Trend including Spar, West Tryal Rocks, Gorgon, Chrysaor, and Dionysus (collectively termed the Greater Gorgon Resource). Recent discoveries at Chrysaor and Dionysus emphasise the role of subtle 3D seismic attributes in finding hydrocarbons and defining reserves with a minimum number of wells.The Gorgon, Chrysaor, and Dionysus fields were covered by 3D seismic data shot in 1991 and 1995, which led WAPET to discover Chrysaor and later Dionysus. Subsequent to the 3D acquisitions, field reservoirs have been correlated with anomalous seismic events (seismic amplitude and amplitude versus offset) that conform to depth structure. Follow-up work has shown that combining these 3D seismic attributes improves the prediction of wet sands, gas sands, and other lithologies.The resulting understanding and confidence provided by this 3D seismic has driven an aggressive exploration program and defined field reserves at a high confidence level. Results include the recent award of permit area WA-267-P to WAPET and the ongoing studies to begin development of the Greater Gorgon Resource.

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3D seismic-assisted CO2-EOR Flow Simulation for the Tensleep Formation at Teapot Dome, USA

Journal of Sustainable Energy Engineering ◽

10.7569/jsee.2017.629504 ◽

2017 ◽

Vol 5 (1) ◽

pp. 47-66

Author(s):

Payam Kavousi Ghahfarokhi ◽

Thomas H. Wilson ◽

Alan Lee Brown

Keyword(s):

Flow Simulation ◽

3D Seismic ◽

Teapot Dome ◽

Co2 Eor ◽

Tensleep Formation

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Amplitude and frequency anomalies in regional 3D seismic data surrounding the Mallik 5L-38 research site, Mackenzie Delta, Northwest Territories, Canada

Geophysics ◽

10.1190/1.2338332 ◽

2006 ◽

Vol 71 (6) ◽

pp. B183-B191 ◽

Cited By ~ 18

Author(s):

M. Riedel ◽

G. Bellefleur ◽

S. R. Dallimore ◽

A. Taylor ◽

J. F. Wright

Keyword(s):

Northwest Territories ◽

Gas Hydrate ◽

Seismic Data ◽

Ratio Method ◽

Unfrozen Water ◽

3D Seismic ◽

Mackenzie Delta ◽

Data Set ◽

Seismic Amplitude ◽

3D Seismic Data

Amplitude and frequency anomalies associated with lakes and drainage systems were observed in a 3D seismic data set acquired in the Mallik area, Mackenzie Delta, Northwest Territories, Canada. The site is characterized by large gas hydrate deposits inferred from well-log analyses and coring. Regional interpretation of the gas hydrate occurrences is mainly based on seismic amplitude anomalies, such as brightening or blanking of seismic energy. Thus, the scope of this research is to understand the nature of the amplitude behavior in the seismic data. We have therefore analyzed the 3D seismic data to define areas with amplitude reduction due to contamination from lakes and channels and to distinguish them from areas where amplitude blanking may be a geologic signal. We have used the spectral ratio method to define attenuation (Q) over different areas in the 3D volume and subsequently applied Q-compensation to attenuate lateral variations ofdispersive absorption. Underneath larger lakes, seismic amplitude is reduced and the frequency content is reduced to [Formula: see text], which is half the original bandwidth. Traces with source-receiver pairs located inside of lakes show an attenuation factor Q of [Formula: see text], approximately half of that obtained for source-receiver pairs situated on deep, continuous permafrost outside of lakes. Deeper reflections occasionally identified underneath lakes show low-velocity-related pull-down. The vertical extent of the washout zones is enhanced by acquisition with limited offsets and from processing parameters such as harsh mute functions to reduce noise from surface waves. The strong attenuation and seismic pull-down may indicate the presence of unfrozen water in deeper lakes and unfrozen pore water within the sediments underlying the lakes. Thus, the blanking underneath lakes is not necessarily related to gas migration or other in situ changes in physical properties potentially associated with the presence of gas hydrate.

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Seismic attributes and structural interpretation—it takes two to tango...

The APPEA Journal ◽

10.1071/aj11035 ◽

2012 ◽

Vol 52 (1) ◽

pp. 437 ◽

Cited By ~ 2

Author(s):

Guillaume Backé ◽

Ernest Swierczek ◽

Justin MacDonald ◽

Adam Bailey ◽

David Tassone ◽

...

Keyword(s):

Structural Information ◽

Median Filter ◽

Seismic Attributes ◽

3D Seismic ◽

Seismic Amplitude ◽

The North ◽

Amplitude Data ◽

Fracture Models ◽

Processing Techniques

In this paper, different 3D seismic attributes calculated to improve the accuracy and robustness of structural interpretations in several energy-rich Australian basins are compared. Detailed and precise fault and fracture maps are crucial not only for initial petroleum play assessment, but also for fault seal analysis and reservoir integrity studies. Robust fault and fracture models are also needed to improve the design of reservoir simulation programs and to manage the long-term containment of gas in geological formations. Different attributes (including coherency, dip-steered similarity, dip-steered median filter, dip-steered variance, apparent dip, and dip-steered most-positive and most-negative curvatures) from an array of 3D seismic datasets to better image structural fabrics, such as normal and different fractures patterns, in the North Perth, Cooper, Ceduna, Otway and Gippsland basins have been calculated. The results provide a remarkable improvement in the quality and precision of structural maps using this multi-attribute mapping workflow by comparison with more conventional maps produced, solely using seismic amplitude data. The key to the successful application of multi-attribute structural analysis, however, remains with the ability of the interpreter to identify meaningful structural information from a large volume of data. Thus, the structural expertise of the interpreter remains as the cornerstone to making geological sense of the various seismic processing techniques available.

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Imposing interpretational constraints on a seismic interpretation CNN

Geophysics ◽

10.1190/geo2020-0449.1 ◽

2021 ◽

pp. 1-36

Author(s):

Haibin Di ◽

Cen Li ◽

Stewart Smith ◽

Zhun Li ◽

Aria Abubakar

Keyword(s):

Seismic Data ◽

Recent Progress ◽

Facies Analysis ◽

Three Dimensional ◽

Seismic Interpretation ◽

3D Seismic ◽

Geologic Time ◽

Seismic Amplitude ◽

Subsurface Geology ◽

3D Seismic Data

With the expanding size of three-dimensional (3D) seismic data, manual seismic interpretation becomes time consuming and labor intensive. For automating this process, the recent progress in machine learning, particularly the convolutional neural networks (CNNs), has been introduced into the seismic community and successfully implemented for interpreting seismic structural and stratigraphic features. In principle, such automation aims at mimicking the intelligence of experienced seismic interpreters to annotate subsurface geology both accurately and efficiently. However, most of the implementations and applications are relatively simple in their CNN architectures, which primary rely on the seismic amplitude but undesirably fail to fully use the pre-known geologic knowledge and/or solid interpretational rules of an experienced interpreter who works on the same task. A general applicable framework is proposed for integrating a seismic interpretation CNN with such commonly-used knowledge and rules as constraints. Three example use cases, including relative geologic time-guided facies analysis, layer-customized fault detection, and fault-oriented stratigraphy mapping, are provided for both illustrating how one or more constraints can be technically imposed and demonstrating what added values such a constrained CNN can bring. It is concluded that the imposition of interpretational constraints is capable of improving CNN-assisted seismic interpretation and better assisting the tasks of subsurface mapping and modeling.

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3D seismic image processing for unconformities

Geophysics ◽

10.1190/geo2014-0323.1 ◽

2015 ◽

Vol 80 (2) ◽

pp. IM35-IM44 ◽

Cited By ~ 30

Author(s):

Xinming Wu ◽

Dave Hale

Keyword(s):

Image Processing ◽

3D Seismic ◽

Amplitude Image ◽

Tensor Method ◽

Seismic Amplitude ◽

Seismic Image ◽

Automatic Methods ◽

Normal Vectors ◽

Seismic Reflectors ◽

Seismic Images

In seismic images, an unconformity can be first identified by reflector terminations (i.e., truncation, toplap, onlap, or downlap), and then it can be traced downdip to its corresponding correlative conformity, or updip to a parallel unconformity; for example, in topsets. Unconformity detection is a significant aspect of seismic stratigraphic interpretation, but most automatic methods work only in 2D and can only detect angular unconformities with reflector terminations. Moreover, unconformities pose challenges for automatic techniques used in seismic interpretation. First, it is difficult to accurately estimate normal vectors or slopes of seismic reflectors at an unconformity with multioriented structures due to reflector terminations. Second, seismic flattening methods cannot correctly flatten reflectors at unconformities that represent hiatuses or geologic age gaps. We have developed a 3D unconformity attribute computed from a seismic amplitude image to detect unconformities by highlighting the angular unconformities and corresponding parallel unconformities or correlative conformities. These detected unconformity surfaces were further used as constraints for a structure-tensor method to more accurately estimate seismic normal vectors at unconformities. Finally, using detected unconformities as constraints and more accurate normal vectors, we could better flatten seismic images with unconformities.

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