首页 | 本学科首页   官方微博 | 高级检索  
相似文献
 共查询到20条相似文献，搜索用时 29 毫秒
1.
Fluid depletion within a compacting reservoir can lead to significant stress and strain changes and potentially severe geomechanical issues, both inside and outside the reservoir. We extend previous research of time‐lapse seismic interpretation by incorporating synthetic near‐offset and full‐offset common‐midpoint reflection data using anisotropic ray tracing to investigate uncertainties in time‐lapse seismic observations. The time‐lapse seismic simulations use dynamic elasticity models built from hydro‐geomechanical simulation output and a stress‐dependent rock physics model. The reservoir model is a conceptual two‐fault graben reservoir, where we allow the fault fluid‐flow transmissibility to vary from high to low to simulate non‐compartmentalized and compartmentalized reservoirs, respectively. The results indicate time‐lapse seismic amplitude changes and travel‐time shifts can be used to qualitatively identify reservoir compartmentalization. Due to the high repeatability and good quality of the time‐lapse synthetic dataset, the estimated travel‐time shifts and amplitude changes for near‐offset data match the true model subsurface changes with minimal errors. A 1D velocity–strain relation was used to estimate the vertical velocity change for the reservoir bottom interface by applying zero‐offset time shifts from both the near‐offset and full‐offset measurements. For near‐offset data, the estimated P‐wave velocity changes were within 10% of the true value. However, for full‐offset data, time‐lapse attributes are quantitatively reliable using standard time‐lapse seismic methods when an updated velocity model is used rather than the baseline model.  相似文献   

2.
Sensitivity of time-lapse seismic to reservoir stress path   总被引：1，自引：1，他引：1  
The change in reservoir pore pressure due to the production of hydrocarbons leads to anisotropic changes in the stress field acting on the reservoir. Reservoir stress path is defined as the ratio of the change in effective horizontal stress to the change in effective vertical stress from the initial reservoir conditions, and strongly influences the depletion‐induced compaction behaviour of the reservoir. Seismic velocities in sandstones vary with stress due to the presence of stress‐sensitive regions within the rock, such as grain boundaries, microcracks, fractures, etc. Since the response of any microcracks and grain boundaries to a change in stress depends on their orientation relative to the principal stress axes, elastic‐wave velocities are sensitive to reservoir stress path. The vertical P‐ and S‐wave velocities, the small‐offset P‐ and SV‐wave normal‐moveout (NMO) velocities, and the P‐wave amplitude‐versus‐offset (AVO) are sensitive to different combinations of vertical and horizontal stress. The relationships between these quantities and the change in stress can be calibrated using a repeat seismic, sonic log, checkshot or vertical seismic profile (VSP) at the location of a well at which the change in reservoir pressure has been measured. Alternatively, the variation of velocity with azimuth and distance from the borehole, obtained by dipole radial profiling, can be used. Having calibrated these relationships, the theory allows the reservoir stress path to be monitored using time‐lapse seismic by combining changes in the vertical P‐wave impedance, changes in the P‐wave NMO and AVO behaviour, and changes in the S‐wave impedance.  相似文献   

3.
Quantitative detection of fluid distribution using time-lapse seismic   总被引：1，自引：0，他引：1  
Although previous seismic monitoring studies have revealed several relationships between seismic responses and changes in reservoir rock properties, the quantitative evaluation of time‐lapse seismic data remains a challenge. In most cases of time‐lapse seismic analysis, fluid and/or pressure changes are detected qualitatively by changes in amplitude strength, traveltime and/or Poisson's ratio. We present the steps for time‐lapse seismic analysis, considering the pressure effect and the saturation scale of fluids. We then demonstrate a deterministic workflow for computing the fluid saturation in a reservoir in order to evaluate time‐lapse seismic data. In this approach, we derive the physical properties of the water‐saturated sandstone reservoir, based on the following inputs: VP, VS, ρ and the shale volume from seismic analysis, the average properties of sand grains, and formation‐water properties. Next, by comparing the in‐situ fluid‐saturated properties with the 100% formation‐water‐saturated reservoir properties, we determine the bulk modulus and density of the in‐situ fluid. Solving three simultaneous equations (relating the saturations of water, oil and gas in terms of the bulk modulus, density and the total saturation), we compute the saturation of each fluid. We use a real time‐lapse seismic data set from an oilfield in the North Sea for a case study.  相似文献   

4.
The relationship between Vp and Vs may be used to predict Vs where only Vp is known. Vp/Vs is also used to identify pore fluids from seismic data and amplitude variation with offset analysis. Theoretical, physical, as well as statistical empirical Vp‐Vs relationships have been proposed for reservoir characterization when shear‐wave data are not available. In published work, the focus is primarily on the Vp‐Vs relationship of quartzitic sandstone. In order to broaden the picture we present Vp‐Vs relationships of greensand composed of quartz and glauconite by using data from the Paleocene greensand Nini oil field in the North Sea. A Vp‐Vs relationship derived from modelling is compared with empirical Vp‐Vs regressions from laboratory data as well as from log data. The accuracy of Vs prediction is quantified in terms of root‐mean‐square error. We find that the Vp‐Vs relationship derived from modelling works well for greensand shear‐wave velocity prediction. We model the seismic response of glauconitic greensand by using laboratory data from the Nini field. Our studies here reveal that brine‐saturated glauconitic greensand can have a similar seismic response to that from oil‐saturated quartzitic sandstone and that oil‐saturated strongly cemented greensand can have a similar amplitude variation with offset response to that from brine‐saturated weakly cemented greensand.  相似文献   

5.
An approximation is developed that allows mapped 4D seismic amplitudes and time‐shifts to be related directly to the weighted linear sum of pore pressure and saturation changes. The weights in this relation are identified as key groups of parameters from a petroelastic model and include the reservoir porosity. This dependence on groups of parameters explains the inherent non‐uniqueness of this problem experienced by previous researchers. The proposed relation is of use in 4D seismic data feasibility studies and inversion and interpretation of the 4D seismic response in terms of pore pressure and water saturation changes. A further result is drawn from analysis of data from the North Sea and West Africa, which reveals that the relative interplay between the effects of pore pressure and saturation changes on the seismic data can be simplified to the control of a single, spatially variant parameter CS/CP. Combining these results with those from published literature, we find that CS/CP = 8 appears to be a generality across a range of clastic reservoirs with a similar mean porosity. Using this CS/CP value, an in situ seismic‐scale constraint for the rock stress sensitivity component of the petroelastic model is constructed considering this component carries the largest uncertainty.  相似文献   

6.
We have studied 56 unfractured chalk samples of the Upper Cretaceous Tor Formation of the Dan, South Arne and Gorm Fields, Danish North Sea. The samples have porosities of between 14% and 45% and calcite content of over 95%. The ultrasonic compressional‐ and shear‐wave velocities (VP and VS) for dry and water‐saturated samples were measured at up to 75 bar confining hydrostatic pressure corresponding to effective stress in the reservoir. The porosity is the main control of the ultrasonic velocities and therefore of the elastic moduli. The elastic moduli are slightly higher for samples from the South Arne Field than from the Dan Field for identical porosities. This difference may be due to textural differences between the chalk at the two locations because we observe that large grains (i.e. filled microfossils and fossil fragments) that occur more frequently in samples from the Dan Field have a porosity‐reducing effect and that samples rich in large grains have a relatively low porosity for a given P‐wave modulus. The clay content in the samples is low and is mainly represented by either kaolinite or smectite; samples with smectite have a lower P‐wave modulus than samples with kaolinite at equal porosity. We find that ultrasonic VP and VS of dry chalk samples can be satisfactorily estimated with Gassmann's relationships from data for water‐saturated samples. A pronounced difference between the VP/VS ratios for dry and water‐saturated chalk samples indicates promising results for seismic amplitude‐versus‐offset analyses.  相似文献   

7.
The use of relaxation mechanisms has recently made it possible to simulate viscoelastic (Q) effects accurately in time-domain numerical computations of seismic responses. As a result, seismograms may now be synthesized for models with arbitrary spatial variations in compressional- and shear-wave quality factors (Q9, and Qs, as well as in density (ρ) and compressional- and shear-wave velocities (Vp, and Vs). Reflections produced by Q contrasts alone may have amplitudes as large as those produced by velocity contrasts. Q effects, including their interaction with Vp, Vs and p, contribute significantly to the seismic response of reservoirs. For band-limited data at typical seismic frequencies, the effects of Q on reflectivity and attenuation are more visible than those on dispersion. Synthetic examples include practical applications to reservoir exploration, evaluation and monitoring. Q effects are clearly visible in both surface and offset vertical seismic profile data. Thus, AVO analyses that neglect Q may produce erroneous conclusions.  相似文献   

8.
The injection of CO2 at the Ketzin pilot site commenced in June 2008 and was terminated in August 2013 after 67 kT had been injected into a saline formation at a depth of 630–650 m. As part of the site monitoring program, four 3D surface seismic surveys have been acquired to date, one baseline and three repeats, of which two were conducted during the injection period, and one during the post‐injection phase. The surveys have provided the most comprehensive images of the spreading CO2 plume within the reservoir layer. Both petrophysical experiments on core samples from the Ketzin reservoir and spectral decomposition of the 3D time‐lapse seismic data show that the reservoir pore pressure change due to CO2 injection has a rather minor impact on the seismic amplitudes. Therefore, the observed amplitude anomaly is interpreted to be mainly due to CO2 saturation. In this study, amplitude versus offset analysis has been applied to investigate the amplitude versus offset response from the top of the sandstone reservoir during the injection and post‐injection phases, and utilize it to obtain a more quantitative assessment of the CO2 gaseous saturation changes. Based on the amplitude versus offset modelling, a prominent decrease in the intercept values imaged at the top of the reservoir around the injection well is indeed associated solely with the CO2 saturation increase. Any change in the gradient values, which would, in case it was positive, be the only signature induced by the reservoir pressure variations, has not been observed. The amplitude versus offset intercept change is, therefore, entirely ascribed to CO2 saturation and used for its quantitative assessment. The estimated CO2 saturation values around the injection area in the range of 40%–60% are similar to those obtained earlier from pulsed neutron‐gamma logging. The highest values of 80% are found in the second seismic repeat in close vicinity to the injection and observation wells.  相似文献   

9.
The Ketzin project provides an experimental pilot test site for the geological storage of CO2. Seismic monitoring of the Ketzin site comprises 2D and 3D time-lapse experiments with baseline experiments in 2005. The first repeat 2D survey was acquired in 2009 after 22 kt of CO2 had been injected into the Stuttgart Formation at approximately 630 m depth. Main objectives of the 2D seismic surveys were the imaging of geological structures, detection of injected CO2, and comparison with the 3D surveys. Time-lapse processing highlighted the importance of detailed static corrections to account for travel time delays, which are attributed to different near-surface velocities during the survey periods. Compensation for these delays has been performed using both pre-stack static corrections and post-stack static corrections. The pre-stack method decomposes the travel time delays of baseline and repeat datasets in a surface consistent manner, while the latter cross-aligns baseline and repeat stacked sections along a reference horizon.Application of the static corrections improves the S/N ratio of the time-lapse sections significantly. Based on our results, it is recommended to apply a combination of both corrections when time-lapse processing faces considerable near-surface velocity changes. Processing of the datasets demonstrates that the decomposed solution of the pre-stack static corrections can be used for interpretation of changes in near-surface velocities. In particular, the long-wavelength part of the solution indicates an increase in soil moisture or a shallower groundwater table in the repeat survey.Comparison with the processing results of 2D and 3D surveys shows that both image the subsurface, but with local variations which are mainly associated to differences in the acquisition geometry and source types used. Interpretation of baseline and repeat stacks shows that no CO2 related time-lapse signature is observable where the 2D lines allow monitoring of the reservoir. This finding is consistent with the time-lapse results of the 3D surveys, which show an increase in reflection amplitude centered around the injection well. To further investigate any potential CO2 signature, an amplitude versus offset (AVO) analysis was performed. The time-lapse analysis of the AVO does not indicate the presence of CO2, as expected, but shows signs of a pressure response in the repeat data.  相似文献   

10.
Filters for migrated offset substacks are designed by partial coherence analysis to predict ‘normal’ amplitude variation with offset (AVO) in an anomaly free area. The same prediction filters generate localized prediction errors when applied in an AVO‐anomalous interval. These prediction errors are quantitatively related to the AVO gradient anomalies in a background that is related to the minimum AVO anomaly detectable from the data. The prediction‐error section is thus used to define a reliability threshold for the identification of AVO anomalies. Coherence analysis also enables quality control of AVO analysis and inversion. For example, predictions that are non‐localized and/or do not show structural conformity may indicate spatial variations in amplitude–offset scaling, seismic wavelet or signal‐to‐noise (S/N) ratio content. Scaling and waveform variations can be identified from inspection of the prediction filters and their frequency responses. S/N ratios can be estimated via multiple coherence analysis. AVO inversion of seismic data is unstable if not constrained. However, the use of a constraint on the estimated parameters has the undesirable effect of introducing biases into the inverted results: an additional bias‐correction step is then needed to retrieve unbiased results. An alternative form of AVO inversion that avoids additional corrections is proposed. This inversion is also fast as it inverts only AVO anomalies. A spectral coherence matching technique is employed to transform a zero‐offset extrapolation or near‐offset substack into P‐wave impedance. The same technique is applied to the prediction‐error section obtained by means of partial coherence, in order to estimate S‐wave velocity to P‐wave velocity (VS/VP) ratios. Both techniques assume that accurate well ties, reliable density measurements and P‐wave and S‐wave velocity logs are available, and that impedance contrasts are not too strong. A full Zoeppritz inversion is required when impedance contrasts that are too high are encountered. An added assumption is made for the inversion to the VS/VP ratio, i.e. the Gassmann fluid‐substitution theory is valid within the reservoir area. One synthetic example and one real North Sea in‐line survey illustrate the application of the two coherence methods.  相似文献   

11.
Time‐lapse 3D seismic reflection data, covering the CO2 storage operation at the Snøhvit gas field in the Barents Sea, show clear amplitude and time‐delay differences following injection. The nature and extent of these changes suggest that increased pore fluid pressure contributes to the observed seismic response, in addition to a saturation effect. Spectral decomposition using the smoothed pseudo‐Wigner–Ville distribution has been used to derive discrete‐frequency reflection amplitudes from around the base of the CO2 storage reservoir. These are utilized to determine the lateral variation in peak tuning frequency across the seismic anomaly as this provides a direct proxy for the thickness of the causative feature. Under the assumption that the lateral and vertical extents of the respective saturation and pressure changes following CO2 injection will be significantly different, discrete spectral amplitudes are used to distinguish between the two effects. A clear spatial separation is observed in the distribution of low‐ and high‐frequency tuning. This is used to discriminate between direct fluid substitution of CO2, as a thin layer, and pressure changes that are distributed across a greater thickness of the storage reservoir. The results reveal a striking correlation with findings derived from pressure and saturation discrimination algorithms based on amplitude versus offset analysis.  相似文献   

12.
Azimuthal variation in AVO response for fractured gas sands   总被引：1，自引：0，他引：1  
Natural fractures in reservoirs play an important role in determining fluid flow during production, and hence the density and orientation of fractures is of great interest. In the presence of aligned vertical fractures, the reflection amplitude at finite offset varies with azimuth. The effect of natural fractures on the azimuthal AVO response from a gas-sandstone reservoir encased within shale is investigated. A simple expression for the difference in P-wave reflection coefficient from the top of the reservoir parallel and perpendicular to the strike of the fractures is obtained in terms of the normal and tangential compliances, ZN and ZT, of the fractures. This expression is valid for small anisotropy and material contrasts and is compared with the results of numerical modelling. For a given value of ZT, the azimuthal variation in reflection coefficient at moderate offsets is found to increase with decreasing ZN/ZT. For gas-filled open fractures ZN/ZT ≈ 1, but a lower ratio of ZN/ZT may result from the presence of cement or clay within the fractures, or from the presence of a fluid with non-zero bulk modulus. For ZN/ZT = 1 and moderate offsets, the variation with offset of the reflection coefficient from the top of the fractured unit is dominated by the contrast in Poisson's ratio between the gas sand and the overlying shale, the effect of fractures only becoming noticeable as the critical angle for the unfractured sandstone is approached. However, for reflections from the base of the fractured unit, the variation in reflection amplitude with azimuth is much greater at conventional seismic offsets than for the reflection from the top. Azimuthal variations in the strength of the reflection from the top of the reservoir depend only on the variation in reflection coefficient, whereas the raypath is also a function of azimuth for reflections from the base of the fractured unit, leading to stronger, more visible, variations of AVO with azimuth. It follows that an azimuthal variation in AVO due to fractures in the overburden may be misinterpreted as due to the presence of aligned fractures in the reservoir.  相似文献   

13.
  相似文献   

14.
Elastic rock properties can be estimated from prestack seismic data using amplitude variation with offset analysis. P‐wave, S‐wave and density ‘reflectivities’, or contrasts, can be inverted from angle‐band stacks. The ‘reflectivities’ are then inverted to absolute acoustic impedance, shear impedance and density. These rock properties can be used to map reservoir parameters through all stages of field development and production. When P‐wave contrast is small, or gas clouds obscure reservoir zones, multicomponent ocean‐bottom recording of converted‐waves (P to S or Ps) data provides reliable mapping of reservoir boundaries. Angle‐band stacks of multicomponent P‐wave (Pz) and Ps data can also be inverted jointly. In this paper Aki‐Richards equations are used without simplifications to invert angle‐band stacks to ‘reflectivities’. This enables the use of reflection seismic data beyond 30° of incident angles compared to the conventional amplitude variation with offset analysis. It, in turn, provides better shear impedance and density estimates. An important input to amplitude variation with offset analysis is the Vs/Vp ratio. Conventional methods use a constant or a time‐varying Vs/Vp model. Here, a time‐ and space‐varying model is used during the computation of the ‘reflectivities’. The Vs/Vp model is generated using well log data and picked horizons. For multicomponent data applications, the latter model can also be generated from processing Vs/Vp models and available well data. Reservoir rock properties such as λρ, μρ, Poisson's ratio and bulk modulus can be computed from acoustic impedance, shear impedance and density for pore fill and lithology identification. λ and μ are the Lamé constants and ρ is density. These estimations can also be used for a more efficient log property mapping. Vp/Vs ratio or Poisson's ratio, λρ and weighted stacks, such as the one computed from λρ and λ/μ, are good gas/oil and oil/water contact indicators, i.e., pore fill indicators, while μρ mainly indicates lithology. μρ is also affected by pressure changes. Results from a multicomponent data set are used to illustrate mapping of gas, oil and water saturation and lithology in a Tertiary sand/shale setting. Whilst initial log crossplot analysis suggested that pore fill discrimination may be possible, the inversion was not successful in revealing fluid effects. However, rock properties computed from acoustic impedance, shear impedance and density estimates provided good lithology indicators; pore fill identification was less successful. Neural network analysis using computed rock properties provided good indication of sand/shale distribution away from the existing wells and complemented the results depicted from individual rock property inversions.  相似文献   

15.
Part one of this paper reported results from experimental compaction measurements of unconsolidated natural sand samples with different mineralogical compositions and textures. The experimental setup was designed with several cycles of stress loading and unloading applied to the samples. The setup was aimed to simulate a stress condition where sediments underwent episodes of compaction, uplift and erosion. P-wave and S-wave velocities and corresponding petrophysical (porosity and density) properties were reported. In this second part of the paper, rock physics modelling utilizing existing rock physics models to evaluate the model validity for measured data from part one were presented. The results show that a friable sand model, which was established for normally compacted sediments is also capable of describing overconsolidated sediments. The velocity–porosity data plotted along the friable sand lines not only describe sorting deterioration, as has been traditionally explained by other studies, but also variations in pre-consolidation stress or degree of stress release. The deviation of the overconsolidated sands away from the normal compaction trend on the VP/VS and acoustic impedance space shows that various stress paths can be predicted on this domain when utilizing rock physics templates. Fluid saturation sensitivity is found to be lower in overconsolidated sands compared to normally consolidated sands. The sensitivity decreases with increasing pre-consolidation stress. This means detectability for four-dimensional fluid saturation changes can be affected if sediments were pre-stressed and unloaded. Well log data from the Barents Sea show similar patterns to the experimental sand data. The findings allow the development of better rock physics diagnostics of unloaded sediments, and the understanding of expected 4D seismic response during time-lapse seismic monitoring of uplifted basins. The studied outcomes also reveal an insight into the friable sand model that its diagnostic value is not only for describing sorting microtextures, but also pre-consolidation stress history. The outcome extends the model application for pre-consolidation stress estimation, for any unconsolidated sands experiencing similar unloading stress conditions to this study.  相似文献   

16.
Utilizing shear-wave (S-wave) data acquired with compressional waves (P-waves) is becoming more common as joint imaging and inversion techniques improve. Interest in S-waves radiated from vertical sources and buried explosives exploits conversion to P-waves as primary reflections (SP-waves) for reducing acquisition costs and for application to legacy data. However, recent investigations overstate the extent of SP-wave illumination and show isotropic processing results with narrow bandwidth frequency and wavenumber data. I demonstrate that illumination with SP-waves is limited in general to near vertical polar angles up to around 30° or 35° for VP/VS of 2 or 3, respectively. At greater angles, S-waves are typically in the P-wave evanescent range and cannot excite SP-wave reflections. Contrary to recent claims, these sources for P-wave do not radiate SH-waves polarized in horizontal planes in all azimuths. I show these properties for isotropic media with radiation expressions for amplitude derived in vector slowness coordinates. Also, I extend these expressions to transversely isotropic media with a vertical symmetry axis to show agreement with synthetic seismic data that only quasi SV-waves are radiated and become more narrowly focused towards 45°. Furthermore, in orthorhombic media, synthetic data show that fast S1- and slow S2-waves polarized parallel and perpendicular to fractures may appear as SV- and SH-waves. For the partially saturated fracture model studied here, S1-wave radiation has broader azimuthal illumination than slow S2-waves, which are more narrowly focused in azimuth. These produce SP-wave splitting signatures on vertical component reflection data that are nearly identical to PS-wave signatures on radial horizontal component data. Separating these fast and slow SP-waves is an additional processing challenge.  相似文献   

17.
Transverse isotropy with a vertical axis of symmetry is a common form of anisotropy in sedimentary basins, and it has a significant influence on the seismic amplitude variation with offset. Although exact solutions and approximations of the PP-wave reflection coefficient for the transversely isotropic media with vertical axis of symmetry have been explicitly studied, it is difficult to apply these equations to amplitude inversion, because more than three parameters need to be estimated, and such an inverse problem is highly ill-posed. In this paper, we propose a seismic amplitude inversion method for the transversely isotropic media with a vertical axis of symmetry based on a modified approximation of the reflection coefficient. This new approximation consists of only three model parameters: attribute A, the impedance (vertical phase velocity multiplied by bulk density); attribute B, shear modulus proportional to an anellipticity parameter (Thomsen's parameter ε−δ); and attribute C, the approximate horizontal P-wave phase velocity, which can be well estimated by using a Bayesian-framework-based inversion method. Using numerical tests we show that the derived approximation has similar accuracy to the existing linear approximation and much higher accuracy than isotropic approximations, especially at large angles of incidence and for strong anisotropy. The new inversion method is validated by using both synthetic data and field seismic data. We show that the inverted attributes are robust for shale-gas reservoir characterization: the shale formation can be discriminated from surrounding formations by using the crossplot of the attributes A and C, and then the gas-bearing shale can be identified through the combination of the attributes A and B. We then propose a rock-physics-based method and a stepwise-inversion-based method to estimate the P-wave anisotropy parameter (Thomsen's parameter ε). The latter is more suitable when subsurface media are strongly heterogeneous. The stepwise inversion produces a stable and accurate Thomsen's parameter ε, which is proved by using both synthetic and field data.  相似文献   

18.
A 3D relocation technique permits precise locations of induced earthquakes. Geostatistical processing using the data of 87 boreholes provides the basis of a precise 3D structure, with a dome geometry. Conventional laboratory mechanical tests performed on deep rock samples (1000 m to 5000 m) define the rock properties at depths similar to those of the seismic events (1<M L<4.2) that range from 1 to 7 km.In the studied period, most (85%), of the events were located above the gas reservoir, with very few located in the reservoir itself. Because the production parameters (50 MPa depletion of the gas pressure reservoir) are homogeneous throughout the gas field, the lateral inhomogeneity of the seismic rupture locations are a consequence of variations in the rheological response of the dome to the deformation induced by gas production.Here a ratio of two is found between the elastic modulus of the seismic rock matrix and the elastic modulus of the aseismic rock matrix. The contrast in strength is at least as great, if not greater. Repeated measured surface deformations involve the whole structure. Spatial and temporal deformations indicate that aseismic deformation is quantitatively the main process of this structural deformation. The heterogeneous stress pattern inferred fromP-axes of induced earthquakes disagrees with the tectonic regional stress field. The radial distribution ofP-axes towards the gas reservoir probably reflects the production induced deformation. The inferred deformation of the dome occurs in response to weak induced stresses.  相似文献   

19.
Statistical methods are available which predict the maximum response of simple oscillators given the peak acceleration (Ap), peak velocity (Vp) or peak displacement (Dp) of seismic ground motions. An alternative parameter, namely an ordinate (or ordinates) of the Fourier amplitude spectrum of ground motion acceleration, FS(f), may in fact be a preferred predictor of peak response, especially in a frequency range close to f. Other statistical methods (attenuation laws) use distance R and other parameters such as magnitude (M), Modified Mercalli epicentral Intensity (Io) and Modified Mercalli site Intensity (MMI or Is) to predict spectral velocity (Sv(f)), etc. In using such approaches, it is most desirable to know the total uncertainty in the predicted peak response of the system given the starting parameter values. An extensive strong motion data set is used to study these questions, The most direct prediction models are found to be preferable (have lower prediction dispersion) but data may not be available in all regions to permit their use.  相似文献   

20.
A system of aligned vertical fractures produces azimuthal variations in stacking velocity and amplitude variation with offset, characteristics often reported in seismic reflection data for hydrocarbon exploration. Studies of associated attenuation anisotropy have been mostly theoretical, laboratory or vertical seismic profiling based. We used an 11 common‐midpoint‐long portion of each of four marine surface‐seismic reflection profiles, intersecting each other at 45° within circa 100 m of a common location, to measure the azimuthal variation of effective attenuation, Q−1eff and stacking velocity, in a shallow interval, about 100 m thick, in which consistently orientated vertical fracturing was expected due to an underlying salt diapirism. We found qualitative and quantitative consistency between the azimuthal variation in the attenuation and stacking velocity, and published amplitude variation with offset results. The 135° azimuth line showed the least apparent attenuation (1000 Q−1eff= 16 ± 7) and the fastest stacking velocity, hence we infer it to be closest to the fracture trend: the orthogonal 45° line showed the most apparent attenuation (1000Q−1eff= 52 ± 15) and slowest stacking velocity. The variation of Q−1eff with azimuth φ is well fitted by 1000Q−1eff = 34 − 18cos[2(φ+40°)] giving a fracture direction of 140 ± 23° (±1SD, derived from ‘bootstrapping’ fits to all 114 combinations of individual common‐midpoint/azimuth measurements), compared to 134 ± 47° from published amplitude variation with offset data. The effects of short‐window spectral estimation and choices of spectral ratio bandwidth and offset ranges used in attenuation analysis, individually give uncertainties of up to ±13° in fracture direction. This magnitude of azimuthal variation can be produced by credible crack geometries (e.g., dry cracks, radius 6.5 m, aspect ratio 3 × 10−5, crack density 0.2) but we do not claim these to be the actual properties of the interval studied, because of the lack of well control (and its consequences for the choice of theoretical model and host rock physical properties) and the small number of azimuths available here.  相似文献   

设为首页 | 免责声明 | 关于勤云 | 加入收藏

Copyright©北京勤云科技发展有限公司  京ICP备09084417号