Seismic reprocessing and interpretation of a fractured-basement play: Texas Panhandle

2017 ◽  
Vol 5 (3) ◽  
pp. SK179-SK187 ◽  
Author(s):  
Thang Ha ◽  
Kurt Marfurt
Keyword(s):  
Horizontal Stress ◽  
Wave Impedance ◽  
Azimuthal Anisotropy ◽  
Oil Field ◽  
P Wave ◽  
Coherent Noise ◽  
Seismic Attribute ◽  
Gas Field ◽  
Direction Parallel ◽  
Head Waves

The Panhandle-Hugoton field, of Texas, Oklahoma, and Kansas, is a giant oil field and is the largest conventional gas field in North America. Most hydrocarbon production in this field comes from the Wichita Uplift area, where the basement is the most shallow. Although the field has been extensively produced, many local hydrocarbon accumulations have not been fully exploited. Recent drilling activity in the survey indicates that some wells produce directly from basement fractures, suggesting a new play type for the area. Because the target is shallow, the seismic data are heavily contaminated by coherent noise, such as ground roll and head waves, creating challenges for seismic processing. To improve the seismic interpretation, we carefully reprocessed the field gathers resulting in improved correlation within the sedimentary and the basement sections. Correlating well control to seismic attribute volumes indicates that a fractured basement gives rise to lower P-wave impedance and strong amplitude versus azimuth anomalies. The azimuthal anisotropy is strongest in a direction parallel to the regional maximum horizontal stress, suggesting that these fractures are open. Coherence anomalies indicate a rugose basement surface, whereas curvature shows two lineament sets, consistent with the weathering and fractured exposure of basement in the Wichita Mountains to the southeast.

Analysis of multiazimuthal VSP data for anisotropy and AVO

Geophysics ◽  
1999 ◽  
Vol 64 (4) ◽  
pp. 1172-1180 ◽  
Author(s):  
W. Scott Leaney ◽  
Colin M. Sayers ◽  
Douglas E. Miller
Keyword(s):  
Fractured Reservoirs ◽  
Vertical Axis ◽  
Horizontal Stress ◽  
Azimuthal Anisotropy ◽  
Carbonate Reservoir ◽  
P Wave ◽  
Fractured Reservoir ◽  
Data Set ◽  
Vsp Data ◽  
The Impact

Multioffset vertical seismic profile (VSP) experiments, commonly referred to as walkaways, enable anisotropy to be measured reliably in the field. The results can be fed into modeling programs to study the impact of anisotropy on velocity analysis, migration, and amplitude versus offset (AVO). Properly designed multioffset VSPs can also provide the target AVO response measured under optimum conditions, since the wavelet is recorded just above the reflectors of interest with minimal reflection point dispersal. In this paper, the multioffset VSP technique is extended to include multioffset azimuths, and a multiazimuthal multiple VSP data set acquired over a carbonate reservoir is analyzed for P-wave anisotropy and AVO. Direct arrival times down to the overlying shale and reflection times and amplitudes from the carbonate are analyzed. Data analysis involves a three‐term fit to account for nonhyperbolic moveout, dip, and azimuthal anisotropy. Results indicate that the overlying shale is transversely isotropic with a vertical axis of symmetry (VTI), while the carbonate shows 4–5% azimuthal anisotropy in traveltimes. The fast direction is consistent with the maximum horizontal stress orientation determined from break‐out logs and is also consistent with the strike of major faults. AVO analysis of the reflection from the top of the carbonate layer shows a critical angle reduction in the fast direction and maximum gradient in the slow direction. This agrees with modeling and indicates a greater amplitude sensitivity in the slow direction—the direction perpendicular to fracture strike. In principle, 3-D surveys should have wide azimuthal coverage to characterize fractured reservoirs. If this is not possible, it is important to have azimuthal line coverage in the minimum horizontal stress direction to optimize the use of AVO for fractured reservoir characterization. This direction can be obtained from multiazimuthal walkaways using the azimuthal P-wave analysis techniques presented.

Stress-induced seismic azimuthal anisotropy, sand-shale content, and depth trends offshore North West Australia

Geophysics ◽  
2017 ◽  
Vol 82 (2) ◽  
pp. C77-C90 ◽  
Author(s):  
Lisa J. Gavin ◽  
David Lumley
Keyword(s):  
Confining Pressure ◽  
Horizontal Stress ◽  
Azimuthal Anisotropy ◽  
P Wave ◽  
Model Parameters ◽  
Burial Depth ◽  
3D Seismic ◽  
Depth Limit ◽  
North West ◽  
S Waves

Seismic azimuthal anisotropy is apparent when P-wave velocities vary with source-receiver azimuth and downward-propagating S-waves split into two quasi-S-waves, polarized in orthogonal directions. Not accounting for these effects can degrade seismic image quality and result in erroneous amplitude analysis and geologic interpretations. There are currently no physical models available to describe how azimuthal anisotropy induced by differential horizontal stress varies with sand-shale lithology and depth; we develop a model that does so, in unconsolidated sand-shale sequences offshore North West Australia. Our method naturally introduces two new concepts: “critical anisotropy” and “anisotropic depth limit.” Critical anisotropy is the maximum amount of azimuthal anisotropy expected to be observed at the shallowest sediment burial depth, where the confining pressure and sediment compaction are minimal. The anisotropic depth limit is the maximum depth where the stress-induced azimuthal anisotropy is expected to be observable, where the increasing effects of confining pressure, compaction, and cementation make the sediments insensitive to differential horizontal stress. We test our model on borehole log data acquired in the Stybarrow Field, offshore North West Australia, where significant differential horizontal stress and azimuthal anisotropy are present. We determine our model parameters by performing regressions using dipole shear log velocities, gamma-ray shale volume logs, and depth trend data. We perform a blind test using the model parameters derived from one well to accurately predict the azimuthal anisotropy values at two other wells in an adjacent area. We use our anisotropy predictions to improve the well-tie match of the modeled angle-dependent reflectivity amplitudes to the 3D seismic amplitude variation with offset data observed at the well locations. Future applications of our method may allow the possibility to estimate the sand-shale content over a wide exploration area using anisotropic parameters derived from surface 3D seismic data.

Rock property- and seismic-attribute analysis of a chert reservoir in the Devonian Thirty-one Formation, west Texas, U.S.A.

Geophysics ◽  
2006 ◽  
Vol 71 (5) ◽  
pp. B151-B158 ◽  
Author(s):  
Dongjun (Taller) Fu ◽  
E. Charlotte Sullivan ◽  
Kurt J. Marfurt
Keyword(s):  
Rock Physics ◽  
Wave Impedance ◽  
Seismic Inversion ◽  
P Wave ◽  
Seismic Attribute ◽  
West Texas ◽  
Attribute Analysis ◽  
Bedded Chert ◽  
Petrophysical Logs ◽  
Tripolitic Chert

In west Texas, fractured-chert reservoirs of Devonian age have produced more than 700 million barrels of oil. About the same amount of mobile petroleum remains in place. These reservoirs are characterized by microporosity; they are heterogeneous and compartmented, which results in recovery of less than 30% of the oil in place. In this case study the objective was to use cores, petrophysical logs, rock physics, and seismic attributes to characterize porosity and field-scale fractures. The relations among porosity, velocity, and impedance were explored and also reactions among production, impedance, and lineaments observed in 3D attribute volumes. Laboratory core data show that Gassmann’s fluid-substitution equation works well for microporous tripolitic chert. Also, laboratry measurements show excellent linear correlation between P-wave impedance and porosity. Volumetric calculations of reflector curvature and seismic inversion of acoustic impedance were combined to infer distribution of lithofacies and fractures and to predict porosity. Statistical relations were established between P-wave velocity and porosity measured from cores, between P-wave impedance and producing zones, and between initial production rates and seismic “fracture lineaments.” The strong quantitative correlation between thick-bedded chert lithofacies and seismic impedance was used to map the reservoir. A qualitative inverse relation between the first [Formula: see text] of production and curvature lineaments was documented.

Fracture detection in a carbonate reservoir using a variety of seismic methods

Geophysics ◽  
1999 ◽  
Vol 64 (4) ◽  
pp. 1266-1276 ◽  
Author(s):  
Maria A. Pérez ◽  
Vladimir Grechka ◽  
Reinaldo J. Michelena
Keyword(s):  
Structural Changes ◽  
Horizontal Stress ◽  
Azimuthal Anisotropy ◽  
Carbonate Reservoir ◽  
P Wave ◽  
Regional Trend ◽  
Wave Data ◽  
Fracture Orientation ◽  
Geological Conditions ◽  
Maximum Horizontal Stress

We combine various methods to estimate fracture orientation in a carbonate reservoir located in southwest Venezuela. The methods we apply include the 2-D rotation analysis of 2-D P-S data along three different azimuths, amplitude‐variation‐with‐offset (AVO) of 2-D P-wave data along the same three azimuths, normal‐moveout (NMO) analysis of the same 2-D data, and both 3-D azimuthal AVO and NMO analysis of 3-D P-wave data recorded in the same field. The results of all methods are compared against measures of fracture orientation obtained from Formation microScanner logs recorded at four different locations in the field, regional and local measures of maximum horizontal stress, and the alignment of the major faults that cross the field. P-S data yield fracture orientations that follow the regional trend of the maximum horizontal stress, and are consistent with fracture orientations measured in the wells around the carbonate reservoir. Azimuthal AVO analysis yields a similar regional trend as that obtained from the P-S data, but the resolution is lower. Local variations in fracture orientation derived from 3-D AVO show good correlation with local structural changes. In contrast, due to the influence of a variety of factors, including azimuthal anisotropy and lateral heterogeneity in the overburden, azimuthal NMO analysis over the 3-D P-wave data yields different orientations compared to those obtained by other methods. It is too early to say which particular method is more appropriate and reliable for fracture characterization. The answer will depend on factors that range from local geological conditions to additional costs for acquiring new information.

Filtering coherent noise during prestack depth migration

Geophysics ◽  
1999 ◽  
Vol 64 (4) ◽  
pp. 1054-1066 ◽  
Author(s):  
Bertrand Duquet ◽  
Kurt J. Marfurt
Keyword(s):  
Least Squares ◽  
Oil And Gas ◽  
P Wave ◽  
Velocity Variation ◽  
Coherent Noise ◽  
Lateral Velocity ◽  
Converted Wave ◽  
Depth Migration ◽  
Short Period ◽  
Head Waves

We can often suppress short‐period multiples by predictive deconvolution. We can often suppress coherent noise with significantly different moveout by time‐invariant dip filtering on common‐shot, common‐receiver or NMO-corrected common‐midpoint gathers. Unfortunately, even time variant dip filtering on NMO-corrected data breaks down in the presence of strong lateral velocity variation where the underlying NMO correction breaks down. Underattenuated multiples, converted waves, and diffracted head waves can significantly impede and/or degrade prestack migration‐driven velocity analysis and amplitude variation with offset analysis as well as the quality of the final stacked image. Generalization of time‐variant dip filtering based on conventional NMO corrections of common‐midpoint gathers also breaks down for less conventional data processing situations where we wish to enhance data having nonhyperbolic moveout, such as converted wave energy or long‐offset P-wave reflections in structurally deformed anisotropic media. We present a methodology that defines a depth‐variant velocity filter based on an approximation to the true velocity/depth structure of the earth developed by the interpreter/processor during the normal course of their prestack imaging work flow. Velocity filtering in the depth domain requires the design and calibration of two new least‐squares transforms: a constrained least‐squares common offset Kirchhoff depth migration transform and a transform in residual migration‐velocity moveout space. Each of these new least‐squares transforms can be considered to be generalizations of the well‐known discrete Radon transform commonly used in the oil and gas exploration industry.

scholarly journals Focal mechanism determination of induced microearthquakes in an oil field using full waveforms from shallow and deep seismic networks

Geophysics ◽  
2011 ◽  
Vol 76 (6) ◽  
pp. WC87-WC101 ◽  
Author(s):  
Junlun Li ◽  
H. Sadi Kuleli ◽  
Haijiang Zhang ◽  
M. Nafi Toksöz
Keyword(s):  
Current Knowledge ◽  
Waveform Inversion ◽  
Local Stress ◽  
Focal Mechanisms ◽  
Oil Field ◽  
P Wave ◽  
Stress Regime ◽  
Direction Parallel ◽  
Near Surface ◽  
Seismic Networks

A new, relatively high frequency, full waveform matching method was used to study the focal mechanisms of small, local earthquakes induced in an oil field, which are monitored by a sparse near-surface network and a deep borehole network. The determined source properties are helpful for understanding the local stress regime in this field. During the waveform inversion, we maximize both the phase and amplitude matching between the observed and modeled waveforms. We also use the polarities of the first P-wave arrivals and the average S/P amplitude ratios to better constrain the matching. An objective function is constructed to include all four criteria. For different hypocenters and source types, comprehensive synthetic tests showed that our method is robust enough to determine the focal mechanisms under the current array geometries, even when there is considerable velocity inaccuracy. The application to several tens of induced microseismic events showed satisfactory waveform matching between modeled and observed seismograms. Most of the events have a strike direction parallel with the major northeast-southwest faults in the region, and some events trend parallel with the northwest-southeast conjugate faults. The results are consistent with the in situ well breakout measurements and the current knowledge on the stress direction of this region. The source mechanisms of the studied events, together with the hypocenter distribution, indicate that the microearthquakes are caused by the reactivation of preexisting faults. We observed that the faulting mechanism varies with depth, from strike-slip dominance at shallower depth to normal faulting dominance at greater depth.

Attribute-assisted footprint suppression using a 2D continuous wavelet transform

2018 ◽  
Vol 6 (2) ◽  
pp. T457-T470 ◽  
Author(s):  
Abdulmohsen Alali ◽  
Gabriel Machado ◽  
Kurt J. Marfurt
Keyword(s):  
Wavelet Transform ◽  
Continuous Wavelet Transform ◽  
Seismic Data ◽  
Wave Impedance ◽  
P Wave ◽  
Continuous Wavelet ◽  
Seismic Attribute ◽  
Attribute Data ◽  
Amplitude Data ◽  
Seismic Acquisition

Acquisition footprint manifests itself on 3D seismic data as a repetitive pattern of noise, anomalously high amplitudes, or structural shifts on time or horizon slices that is correlated to the location of the sources and receivers on the earth’s surface. Ideally, footprint suppression should be handled by denser seismic acquisition and more careful prestack processing prior to seismic imaging. In the case in which only legacy data exist, or when economic and time constraints preclude more expensive acquisition and more careful processing, interpreters must deal with data contaminated by footprint. Although accurate time-structure maps can be constructed from footprint-contaminated data, the effect of footprint on subsequent attributes, such as coherence, curvature, spectral components, and P-wave impedance will be exacerbated. We have developed a workflow that uses a 2D continuous wavelet transform to suppress coherent and incoherent noise on poststack seismic data. The method involves decomposing time slices of amplitude and attribute data into voices and magnitudes using 2D wavelets. We exploit the increased seismic attribute sensitivity to the acquisition footprint to design a mask to suppress the footprint on the original amplitude data. The workflow is easy to apply and improves the interpretability of the data and improves the subsequent attribute resolution.

High-resolution passive seismic tomography for 3D velocity, Poisson’s ratio ν, and P-wave quality QP in the Delvina hydrocarbon field, southern Albania

Geophysics ◽  
2011 ◽  
Vol 76 (3) ◽  
pp. B89-B112 ◽  
Author(s):  
G-Akis Tselentis ◽  
Nikolaos Martakis ◽  
Paraskevas Paraskevopoulos ◽  
Athanasios Lois
Keyword(s):  
Wave Velocity ◽  
Seismic Tomography ◽  
Oil Field ◽  
P Wave ◽  
S Wave ◽  
Gas Field ◽  
Data Set ◽  
Geophysical Surveys ◽  
Passive Seismic ◽  
Hydrocarbon Field

We have studied using traveltimes of P- and S-waves and initial seismic-pulse rise-time measurements from natural microearthquakes to derive 3D P-wave velocity VP information (mostly structural) as well as P- and S-wave velocity VP/VS and P-wave quality factor QP information (mostly lithologic) in a known hydrocarbon field in southern Albania. During a 12-month monitoring period, 1860 microearthquakes were located at a 50-station seismic network and were used to obtain the above parameters. The data set included earthquakes with magnitudes ranging from –0.1 to 3.0 R (Richter scale) and focal depths typically occurring between 2 and 10 km. Kohonen neural networks were implemented to facilitate the lithological classification of the passive seismic tomography (PST) results. The obtained results, which agreed with data from nearby wells, helped delineate the structure of the reservoir. Two subregions of the investigated area, one corresponding to an oil field and one to a gas field, were correlated with the PST results. This experiment showed that PST is a powerful new geophysical technique for exploring regions that present seismic penetration problems, difficult topographies, and complicated geologies, such as thrust-belt regions. The method is economical and environmentally friendly, and it can be used to investigate very large regions for the optimal design of planned 2D or 3D conventional geophysical surveys.

Analysis of conventional and converted mode reflections at Putah sink, California using three‐component data

Geophysics ◽  
1990 ◽  
Vol 55 (6) ◽  
pp. 646-659 ◽  
Author(s):  
C. Frasier ◽  
D. Winterstein
Keyword(s):  
Time Window ◽  
Structural Features ◽  
Low Noise ◽  
P Wave ◽  
Bright Spot ◽  
High Signal ◽  
Converted Wave ◽  
Gas Field ◽  
Seismic Line ◽  
S Waves

In 1980 Chevron recorded a three‐component seismic line using vertical (V) and transverse (T) motion vibrators over the Putah sink gas field near Davis, California. The purpose was to record the total vector motion of the various reflection types excited by the two sources, with emphasis on converted P‐S reflections. Analysis of the conventional reflection data agreed with results from the Conoco Shear Wave Group Shoot of 1977–1978. For example, the P‐P wave section had gas‐sand bright spots which were absent in the S‐S wave section. Shot profiles from the V vibrators showed strong P‐S converted wave events on the horizontal radial component (R) as expected. To our surprise, shot records from the T vibrators showed S‐P converted wave events on the V component, with low amplitudes but high signal‐to‐noise (S/N) ratios. These S‐P events were likely products of split S‐waves generated in anisotropic subsurface media. Components of these downgoing waves in the plane of incidence were converted to P‐waves on reflection and arrived at receivers in a low‐noise time window ahead of the S‐S waves. The two types of converted waves (P‐S and S‐P) were first stacked by common midpoint (CMP). The unexpected S‐P section was lower in true amplitude but much higher in S/N ratio than the P‐S section. The Winters gas‐sand bright spot was missing on the converted wave sections, mimicking the S‐S reflectivity as expected. CRP gathers were formed by rebinning data by a simple ray‐tracing formula based on the asymmetry of raypaths. CRP stacking improved P‐S and S‐P event resolution relative to CMP stacking and laterally aligned structural features with their counterparts on P and S sections. Thus, the unexpected S‐P data provided us with an extra check for our converted wave data processing.

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