3D volumetric multispectral estimates of reflector curvature and rotation

Saleh Al-Dossary; Kurt J. Marfurt

doi:10.1190/1.2242449

3D volumetric multispectral estimates of reflector curvature and rotation

Geophysics ◽

10.1190/1.2242449 ◽

2006 ◽

Vol 71 (5) ◽

pp. P41-P51 ◽

Cited By ~ 203

Author(s):

Saleh Al-Dossary ◽

Kurt J. Marfurt

Keyword(s):

Seismic Data ◽

Gulf Coast ◽

Data Sets ◽

Fort Worth ◽

North Texas ◽

Fort Worth Basin ◽

Spectral Estimates ◽

Curvature Estimates ◽

Data Volume ◽

Conventional Mapping

One of the most accepted geologic models is the relation between reflector curvature and the presence of open and closed fractures. Such fractures, as well as other small discontinuities, are relatively small and below the imaging range of conventional seismic data. Depending on the tectonic regime, structural geologists link open fractures to either Gaussian curvature or to curvature in the dip or strike directions. Reflector curvature is fractal in nature, with different tectonic and lithologic effects being illuminated at the [Formula: see text] and [Formula: see text] scales. Until now, such curvature estimates have been limited to the analysis of picked horizons. We have developed what we feel to be the first volumetric spectral estimates of reflector curvature. We find that the most positive and negative curvatures are the most valuable in the conventional mapping of lineations — including faults, folds, and flexures. Curvature is mathematically independent of, and interpretatively complementary to, the well-established coherence geometric attribute. We find the long spectral wavelength curvature estimates to be of particular value in extracting subtle, broad features in the seismic data such as folds, flexures, collapse features, fault drags, and under- and overmigrated fault terminations. We illustrate the value of these spectral curvature estimates and compare them to other attributes through application to two land data sets — a salt dome from the onshore Louisiana Gulf Coast and a fractured/karsted data volume from Fort Worth basin of North Texas.

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Karst related vertical collapse structure and related lineament detection by seismic attributes on Fort Worth basin seismic data volume

10.1190/1.1817638 ◽

2003 ◽

Author(s):

Srinivasa Prasad Jyosyula ◽

Kurt J. Marfurt ◽

E. Charlotte Sullivan

Keyword(s):

Seismic Data ◽

Seismic Attributes ◽

Fort Worth ◽

Fort Worth Basin ◽

Data Volume

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Volumetric aberrancy to map subtle faults and flexures

Interpretation ◽

10.1190/int-2017-0114.1 ◽

2018 ◽

Vol 6 (2) ◽

pp. T349-T365 ◽

Cited By ~ 7

Author(s):

Xuan Qi ◽

Kurt Marfurt

Keyword(s):

Seismic Data ◽

Positive Curvature ◽

Hanging Wall ◽

Barnett Shale ◽

Fort Worth ◽

Gas Reservoir ◽

Fort Worth Basin ◽

Seismic Resolution ◽

Data Volume ◽

String Of Pearls

One of the key tasks of a seismic interpreter is to map lateral changes in surfaces, not only including faults, folds, and flexures, but also incisements, diapirism, and dissolution features. Volumetrically, coherence provides rapid visualization of faults and curvature provides rapid visualization of folds and flexures. Aberrancy measures the lateral change (or gradient) of curvature along a picked or inferred surface. Aberrancy complements curvature and coherence. In normally faulted terrains, the aberrancy anomaly will track the coherence anomaly and fall between the most positive curvature anomaly defining the footwall and the most negative curvature anomaly defining the hanging wall. Aberrancy can delineate faults whose throw falls below the seismic resolution or is distributed across a suite of smaller conjugate faults that do not exhibit a coherence anomaly. Previously limited to horizon computations, we extend aberrancy to uninterpreted seismic data volumes. We apply our volumetric aberrancy calculation to a data volume acquired over the Barnett Shale gas reservoir of the Fort Worth Basin, Texas. In this area, the Barnett Shale is bound on the top by the Marble Falls Limestone and on the bottom by the Ellenburger Dolomite. Basement faulting controls karstification in the Ellenburger, resulting in the well-known “string of pearls” pattern seen on coherence images. Aberrancy delineates small karst features, which are, in many places, too smoothly varying to be detected by coherence. Equally important, aberrancy provides the azimuthal orientation of the fault and flexure anomalies.

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Attribute illumination of basement faults, examples from Cuu Long Basin basement, Vietnam and the Midcontinent, USA

Interpretation ◽

10.1190/int-2013-0091.1 ◽

2014 ◽

Vol 2 (1) ◽

pp. SA119-SA126 ◽

Cited By ~ 2

Author(s):

Ha T. Mai ◽

Olubunmi O. Elebiju ◽

Kurt J. Marfurt

Keyword(s):

Sedimentary Basins ◽

Fort Worth ◽

North Texas ◽

Fort Worth Basin ◽

Diagenetic Alteration ◽

Basement Faults ◽

The Usa ◽

Lead Zinc ◽

Granite Basement ◽

Osage County

Geometric attributes such as coherence and curvature have been very successful in delineating faults in sedimentary basins. Albeit not a common exploration objective, fractured and faulted basement forms important reservoirs in Southern California, Mexico, India, Yemen, and Vietnam. Basement faulting controls hydrothermally altered dolomite in the Appalachian Basin of the USA, and is suspected to play a role in diagenetic alteration of carbonates in the Fort Worth Basin of north Texas where copper has been found in some wells, as well as in Osage County, Oklahoma, not far from the classic Mississippi type lead-zinc deposits. Because of the absence of stratified, coherent reflectors, illumination of basement faults is more problematic than illumination of faults within the sedimentary column. To address these limitations, we make simple modifications to well-established vector attributes including structural dip, azimuth, and amplitude gradients, in combination with variance, and most positive and most negative principal curvature to provide greater interpreter interaction. Using these methods, we can better illuminate fracture “sweet spots” and estimate their intensity and orientation. We apply these methods to better characterize faults in the granite basement of the Cuu Long Basin, Vietnam, and the granite and rhyolite-metarhyolite basement of Osage County, Oklahoma, USA. Cuu Long forms an important unconventional reservoir. In Osage County, we suspect basement control of shallower fractures in the Mississippi chat deposits.

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Approaches to defining reservoir physical properties from 3-D seismic attributes with limited well control: An example from the Jurassic Smackover Formation, Alabama

Geophysics ◽

10.1190/1.1444732 ◽

2000 ◽

Vol 65 (2) ◽

pp. 368-376 ◽

Cited By ~ 28

Author(s):

Bruce S. Hart ◽

Robert S. Balch

Keyword(s):

Seismic Data ◽

Empirical Relationship ◽

Real Data ◽

Seismic Attributes ◽

Data Sets ◽

Small Field ◽

Reservoir Properties ◽

Smackover Formation ◽

Data Volume ◽

Seismic Sections

Much industry interest is centered on how to integrate well data and attributes derived from 3-D seismic data sets in the hope of defining reservoir properties in interwell areas. Unfortunately, the statistical underpinnings of the methods become less robust in areas where only a few wells are available, as might be the case in a new or small field. Especially in areas of limited well availability, we suggest that the physical basis of the attributes selected during the correlation procedure be validated by generating synthetic seismic sections from geologic models, then deriving attributes from the sections. We demonstrate this approach with a case study from Appleton field of southwestern Alabama. In this small field, dolomites of the Jurassic Smackover Formation produce from an anticlinal feature about 3800 m deep. We used available geologic information to generate synthetic seismic sections that showed the expected seismic response of the target formation; then we picked the relevant horizons in a 3-D seismic data volume that spanned the study area. Using multiple regression, we derived an empirical relationship between three seismic attributes of this 3-D volume and a log‐derived porosity indicator. Our choice of attributes was validated by deriving complex trace attributes from our seismic modeling results and confirming that the relationships between well properties and real‐data attributes were physically valid. Additionally, the porosity distribution predicted by the 3-D seismic data was reasonable within the context of the depositional model used for the area. Results from a new well drilled after our study validated our porosity prediction, although our structural prediction for the top of the porosity zone was erroneous. These results remind us that seismic interpretations should be viewed as works in progress which need to be updated when new data become available.

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Tracking Induced Seismicity in the Fort Worth Basin: A Summary of the 2008–2018 North Texas Earthquake Study Catalog

Bulletin of the Seismological Society of America ◽

10.1785/0120190057 ◽

2019 ◽

Vol 109 (4) ◽

pp. 1203-1216 ◽

Cited By ~ 9

Author(s):

Louis Quinones ◽

Heather R. DeShon ◽

SeongJu Jeong ◽

Paul Ogwari ◽

Oner Sufri ◽

...

Keyword(s):

Induced Seismicity ◽

Fluid Injection ◽

Well Log ◽

Fort Worth ◽

North Texas ◽

Wastewater Disposal ◽

Fort Worth Basin ◽

Stress Changes ◽

Seismic Networks ◽

Earthquake Sequences

Abstract Since 2008, earthquake sequences within the Fort Worth basin (FWB), north Texas, have been linked to wastewater disposal activities related to unconventional shale‐gas production. The North Texas Earthquake Study (NTXES) catalog (2008–2018), described and included herein, uses a combination of local and regional seismic networks to track significant seismic sequences in the basin. The FWB earthquakes occur along discrete faults that are relatively far apart (>30 km), allowing for more detailed study of individual sequence development. The three largest sequences (magnitude 3.6+) are monitored by local seismic networks (<15 km epicentral distances), whereas basinwide seismicity outside these three sequences is monitored using regional distance stations. A regional 1D velocity model for the FWB reflects basinwide well log, receiver function, and regional crustal structure studies and is modified for the larger individual earthquake sequences using local well‐log and geology data. Here, we present an mb_Lg relationship appropriate for Texas and a basin‐specific ML relationship, both calculated using attenuation curves developed with the NTXES catalog. Analysis of the catalog reveals that the earthquakes generally occur within the Precambrian basement formation along steeply dipping normal faults, and although overall seismicity rates have decreased since 2016, new faults have become active. Between 2006 and 2018, more than 2 billion barrels of fluids were injected into the Ellenburger formation within the FWB. We observe strong spatial and temporal correlations between the earthquake locations and wastewater disposal well locations and injection volumes, implying that fluid injection activities may be the main driving force of seismicity in the basin. In addition, we observe seismicity occurring at greater distances from injection wells (>10 km) over time, implying that far‐field stress changes associated with fluid injection activities may be an important component to understanding the seismic hazard of induced seismicity sequences.

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Noise suppression of time-migrated gathers using prestack structure-oriented filtering

Interpretation ◽

10.1190/int-2015-0146.1 ◽

2016 ◽

Vol 4 (2) ◽

pp. SG19-SG29 ◽

Cited By ~ 16

Author(s):

Bo Zhang ◽

Tengfei Lin ◽

Shiguang Guo ◽

Oswaldo E. Davogustto ◽

Kurt J. Marfurt

Keyword(s):

Seismic Data ◽

Noise Suppression ◽

Seismic Analysis ◽

Rock Properties ◽

Fort Worth ◽

Edge Preserving ◽

Fort Worth Basin ◽

Seismic Image ◽

Data Conditioning

Prestack seismic analysis provides information on rock properties, lithology, fluid content, and the orientation and intensity of anisotropy. However, such analysis demands high-quality seismic data. Unfortunately, noise is always present in seismic data even after careful processing. Noise in the prestack gathers may not only contaminate the seismic image, thereby lowering the quality of seismic interpretation, but it may also bias the seismic prestack inversion for rock properties, such as acoustic- and shear-impedance estimation. Common postmigration data conditioning includes running window median and Radon filters that are applied to the flattened common reflection point gathers. We have combined filters across the offset and azimuth with edge-preserving filters along the structure to construct a true “5D” filter that preserves amplitude, thereby preconditioning the data for subsequent quantitative analysis. We have evaluated our workflow by applying it to a prestack seismic volume acquired over the Fort Worth Basin, TX. The inverted results from the noise-suppressed prestack gathers are more laterally continuous and have higher correlation with well logs when compared with those inverted from conventional time-migrated gathers.

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Effective medium modeling: How to efficiently infer porosity from seismic data?

Interpretation ◽

10.1190/int-2015-0065.1 ◽

2015 ◽

Vol 3 (4) ◽

pp. SAC1-SAC7 ◽

Cited By ~ 5

Author(s):

Mathilde Adelinet ◽

Mickaële Le Ravalec

Keyword(s):

Seismic Data ◽

Volume Fraction ◽

Effective Medium Theory ◽

Pore Space ◽

Fractured Reservoirs ◽

Crack Density ◽

Main Idea ◽

Effective Medium ◽

Fort Worth ◽

Fort Worth Basin

Many geophysical studies in reservoir characterization focus on the variations in the elastic properties of rocks. They commonly involve seismic data, which are processed in terms of seismic attributes. These processed data still have to be related to the physical properties of the rock mass and the fluids saturating the pore space. This need motivated the development of research projects based upon the effective medium theory (EMT). We have used the EMT to infer porosity and also fracture data from seismic impedances in part of the Fort Worth Basin, Texas. The main idea was to take advantage of the available impedances to characterize porosity in terms of equant pores and cracks. We then focused on the volume fraction of spherical pores and crack density. Shortly thereafter, we developed an effective medium (EM) model that provided numerical responses for seismic impedances. These responses were then compared to the impedances obtained from stratigraphic inversion. The overall procedure consisted in adjusting the input parameters of the EMT model, which were the spherical porosity and the crack density, to minimize the impedance mismatch. Our case study involved two limestone formations of the Fort Worth Basin (the Marble Falls and Ellenburger Formations) and one shaly formation (the Barnett Shale). The results are promising — The EMT turns out to be a very useful tool to explain reservoir and geophysical data in terms of microstructural properties, in particular, for fractured reservoirs.

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