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.

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.

P-wave and S-wave azimuthal anisotropy at a naturally fractured gas reservoir, Bluebell‐Altamont Field, Utah

Geophysics ◽  
1999 ◽  
Vol 64 (4) ◽  
pp. 1312-1328 ◽  
Author(s):  
Heloise B. Lynn ◽  
Wallace E. Beckham ◽  
K. Michele Simon ◽  
C. Richard Bates ◽  
M. Layman ◽  
...  
Keyword(s):  
Azimuthal Anisotropy ◽  
P Wave ◽  
Fracture Density ◽  
Wave Reflections ◽  
S Wave ◽  
Gas Reservoir ◽  
Green River ◽  
Wave Data ◽  
Reflection Data ◽  
Naturally Fractured

Reflection P- and S-wave data were used in an investigation to determine the relative merits and strengths of these two data sets to characterize a naturally fractured gas reservoir in the Tertiary Upper Green River formation. The objective is to evaluate the viability of P-wave seismic to detect the presence of gas‐filled fractures, estimate fracture density and orientation, and compare the results with estimates obtained from the S-wave data. The P-wave response to vertical fractures must be evaluated at different source‐receiver azimuths (travelpaths) relative to fracture strike. Two perpendicular lines of multicomponent reflection data were acquired approximately parallel and normal to the dominant strike of Upper Green River fractures as obtained from outcrop, core analysis, and borehole image logs. The P-wave amplitude response is extracted from prestack amplitude variation with offset (AVO) analysis, which is compared to isotropic‐model AVO responses of gas sand versus brine sand in the Upper Green River. A nine‐component vertical seismic profile (VSP) was also obtained for calibration of S-wave reflections with P-wave reflections, and support of reflection S-wave results. The direction of the fast (S1) shear‐wave component from the reflection data and the VSP coincides with the northwest orientation of Upper Green River fractures, and the direction of maximum horizontal in‐situ stress as determined from borehole ellipticity logs. Significant differences were observed in the P-wave AVO gradient measured parallel and perpendicular to the orientation of Upper Green River fractures. Positive AVO gradients were associated with gas‐producing fractured intervals for propagation normal to fractures. AVO gradients measured normal to fractures at known waterwet zones were near zero or negative. A proportional relationship was observed between the azimuthal variation of the P-wave AVO gradient as measured at the tops of fractured intervals, and the fractional difference between the vertical traveltimes of split S-waves (the “S-wave anisotropy”) of the intervals.

Determination of the principal directions of azimuthal anisotropy from P-wave seismic data

Geophysics ◽  
1998 ◽  
Vol 63 (2) ◽  
pp. 692-706 ◽  
Author(s):  
Subhashis Mallick ◽  
Kenneth L. Craft ◽  
Laurent J. Meister ◽  
Ronald E. Chambers
Keyword(s):  
Anisotropic Medium ◽  
Seismic Data ◽  
Principal Direction ◽  
Azimuthal Anisotropy ◽  
P Wave ◽  
Amplitude Variation ◽  
S Waves ◽  
Wave Data ◽  
Principal Directions ◽  
Qualitative Measure

In an azimuthally anisotropic medium, the principal directions of azimuthal anisotropy are the directions along which the quasi-P- and the quasi-S-waves propagate as pure P and S modes. When azimuthal anisotropy is induced by oriented vertical fractures imposed on an azimuthally isotropic background, two of these principal directions correspond to the directions parallel and perpendicular to the fractures. S-waves propagating through an azimuthally anisotropic medium are sensitive to the direction of their propagation with respect to the principal directions. As a result, primary or mode‐converted multicomponent S-wave data are used to obtain the principal directions. Apart from high acquisition cost, processing and interpretation of multicomponent data require a technology that the seismic industry has not fully developed. Anisotropy detection from conventional P-wave data, on the other hand, has been limited to a few qualitative studies of the amplitude variation with offset (AVO) for different azimuthal directions. To quantify the azimuthal AVO, we studied the amplitude variation with azimuth for P-wave data at fixed offsets. Our results show that such amplitude variation with azimuth is periodic in 2θ, θ being the orientation of the shooting direction with respect to one of the principal directions. For fracture‐induced anisotropy, this principal direction corresponds to the direction parallel or perpendicular to the fractures. We use this periodic azimuthal dependence of P-wave reflection amplitudes to identify two distinct cases of anisotropy detection. The first case is an exactly determined one, where we have observations from three azimuthal lines for every common‐midpoint (CMP) location. We derive equations to compute the orientation of the principal directions for such a case. The second case is an overdetermined one where we have observations from more than three azimuthal lines. Orientation of the principal direction from such an overdetermined case can be obtained from a least‐squares fit to the reflection amplitudes over all the azimuthal directions or by solving many exactly determined problems. In addition to the orientation angle, a qualitative measure of the degree of azimuthal anisotropy can also be obtained from either of the above two cases. When azimuthal anisotropy is induced by oriented vertical fractures, this qualitative measure of anisotropy is proportional to fracture density. Using synthetic seismograms, we demonstrate the robustness of our method in evaluating the principal directions from conventional P-wave seismic data. We also apply our technique to real P-wave data, collected over a wide source‐to‐receiver azimuth distribution. Computations using our method gave an orientation of the principal direction consistent with the general fracture orientation in the area as inferred from other geological and geophysical evidence.

scholarly journals Physical and numerical modeling of tuning and diffraction in azimuthally anisotropic media

Geophysics ◽  
2000 ◽  
Vol 65 (5) ◽  
pp. 1613-1621 ◽  
Author(s):  
Richard L. Gibson ◽  
Stephen Theophanis ◽  
M. Nafi Toksöz
Keyword(s):  
Numerical Modeling ◽  
Fractured Reservoirs ◽  
Homogeneous Model ◽  
Azimuthal Anisotropy ◽  
P Wave ◽  
Orthorhombic Symmetry ◽  
Fractured Reservoir ◽  
Sh Wave ◽  
Wave Data ◽  
Ray Methods

Fractured reservoirs are an important target for exploration and production geophysics, and the azimuthal anisotropy often associated with these reservoirs can strongly influence seismic wave propagation. We created a physical model of a fractured reservoir to simulate some of these propagation effects. The reservoir is represented by a phenolite disk that is thin with respect to the elastic wavelengths in the experiment, creating model dimensions that are representative of realistic reservoirs. Phenolite is strongly anisotropic with orthorhombic symmetry, which suggests that azimuthal amplitude versus offset (AVO) effects should be obvious in data. We acquired both SH- and P-wave data in common‐offset gathers with a near offset and a far offset and found that although the SH-wave data show clear azimuthal variations in AVO, the P-wave signals show no apparent changes with azimuth. We then applied numerical modeling to analyze the data. Because ray methods cannot model diffractions from the disk edge, we first used a ray‐Born technique to simulate variations in waveforms associated with such scattering. The synthetic seismograms reproduced variations in the SH-wave waveforms accurately, though the amplitude contrast between acquisition azimuths was overestimated. Assuming a laterally homogeneous model, we then applied ray methods to simulate tuning effects in SH- and P-wave data and confirmed that in spite of the large contrasts in elastic properties, the tuning of the P-wave reflections from the thin disk changed so there was negligible contrast in AVO with azimuth. Models of field scale reservoirs showed that the same effects could be expected for field applications.

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.

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.

Seismic azimuthal anisotropy analysis after hydraulic fracturing

2013 ◽  
Vol 1 (2) ◽  
pp. SB27-SB36 ◽  
Author(s):  
Kui Zhang ◽  
Yanxia Guo ◽  
Bo Zhang ◽  
Amanda M. Trumbo ◽  
Kurt J. Marfurt
Keyword(s):  
Hydraulic Fracturing ◽  
Anisotropy Field ◽  
Horizontal Wells ◽  
Horizontal Stress ◽  
Azimuthal Anisotropy ◽  
Barnett Shale ◽  
Natural Fractures ◽  
Tight Sandstone ◽  
Induced Fractures ◽  
Maximum Horizontal Stress

Many tight sandstone, limestone, and shale reservoirs require hydraulic fracturing to provide pathways that allow hydrocarbons to reach the well bore. Most of these tight reservoirs are now produced using multiple stages of fracturing through horizontal wells drilled perpendicular to the present-day azimuth of maximum horizontal stress. In a homogeneous media, the induced fractures are thought to propagate perpendicularly to the well, parallel to the azimuth of maximum horizontal stress, thereby efficiently fracturing the rock and draining the reservoir. We evaluated what may be the first anisotropic analysis of a Barnett shale-gas reservoir after extensive hydraulic fracturing and focus on mapping the orientation and intensity of induced fractures and any preexisting factures, with the objective being the identification of reservoir compartmentalization and bypassed pay. The Barnett Shale we studied has near-zero permeability and few if any open natural fractures. We therefore hypothesized that anisotropy is therefore due to the regional northeast–southwest maximum horizontal stress and subsequent hydraulic fracturing. We found the anisotropy to be highly compartmentalized, with the compartment edges being defined by ridges and domes delineated by the most positive principal curvature [Formula: see text]. Microseismic work by others in the same survey indicates that these ridges contain healed natural fractures that form fracture barriers. Mapping such heterogeneous anisotropy field could be critical in planning the location and direction of any future horizontal wells to restimulate the reservoir as production drops.

Azimuthal anisotropy analysis of multiazimuth P-wave seismic data — An example from the Rock Springs Uplift, Wyoming, USA

2018 ◽  
Vol 6 (3) ◽  
pp. T649-T666 ◽  
Author(s):  
Hema S. Sharma ◽  
Subhashis Mallick ◽  
Sumit Verma ◽  
Erin Campbell
Keyword(s):  
Carbon Sequestration ◽  
Seismic Anisotropy ◽  
Waveform Inversion ◽  
Azimuthal Angle ◽  
Azimuthal Anisotropy ◽  
P Wave ◽  
Fracture Density ◽  
Fracture Orientation ◽  
Well Data

Our study area in Rock Sprigs Uplift, Wyoming, lies close to the carbon dioxide ([Formula: see text])-producing Jim Bridger power plant, and hence it is a good site for carbon sequestration. Two subsurface reservoirs within this area are being analyzed for their capability of long-term carbon storage. The presence and orientation of fractures within a reservoir and the associated seal govern the efficiency and long-term effectiveness of [Formula: see text] storage. The presence of natural fractures gives rise to seismic anisotropy that is related to the fracture orientation and density. This work analyzed P-wave multiazimuth seismic amplitude and well data from a potential carbon sequestration site for the anisotropy analysis. Using prestack waveform inversion, accurate azimuthal velocities were obtained for offset-to-angle transformation and to compute azimuthal angle gathers. These angle gathers were then stacked for each azimuth and analyzed for azimuthal anisotropy to estimate the fracture orientation and relative fracture density. Finally, by corroborating the results of the seismic azimuthal analysis with well data, it was confirmed that the results from the azimuthal analysis of the angle stacks are related to the fracture orientation and density.

Azimuthal anisotropy analysis of wide-azimuth P-wave seismic data for fracture orientation and density characterization in a tight gas reservoir

2020 ◽  
Vol 8 (1) ◽  
pp. SA73-SA83
Author(s):  
Wanxue Xie ◽  
Guangming He ◽  
Le Li ◽  
Degang Jin ◽  
Dan Chen ◽  
...  
Keyword(s):  
Wave Velocity ◽  
Seismic Data ◽  
Transverse Isotropy ◽  
Azimuthal Anisotropy ◽  
P Wave ◽  
Velocity Variation ◽  
Imaging Data ◽  
Fracture Orientation ◽  
P Wave Velocity ◽  
Tight Gas Reservoir

The role of anisotropy in fracture detection has dramatically increased with the advent of wide-azimuth (WAZ) and high-density seismic acquisition. Fracture prediction using horizontal transverse isotropy (HTI) anisotropic theory is a useful tool for identifying reservoir characteristics. We have developed an approach for fracture density and orientation estimation based on the combination of a velocity variation with azimuth (VVAZ) and an amplitude variation with azimuth (AVAZ) analysis workflow. First, we sort the prestack WAZ data into offset vector tile (OVT) sectors and perform VVAZ inversion by elliptical velocity fitting of measured azimuth-differential traveltimes. In this step, we can predict the fast P-wave velocity, slow P-wave velocity, and fracture orientation. Second, we apply AVAZ inversion to extract more accurate predictions of the anisotropic gradient and fracture orientation. We implement the method with 3D prestack WAZ seismic data acquired in the Sichuan Basin, from the southwest part of China. The field data example indicates that the inversion results agree with geologic information and well-log imaging data, which confirm the effectiveness of this technology.

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