Seismic Amplitude Differences Research Articles

Volcanic-controlled basin architecture variation and dynamic sediment filling in the South Lufeng Sag, South China Sea

Volcanic-controlled changes of basin architectures and sediments have given rise to diverse and rapidly evolving “dynamic geomorphology,” which poses challenges to successful petroleum development. Nonetheless, the accompanying volcanic deposits and landforms often produce rich and distinct seismic responses within conventional sedimentary layers, offering vital support in addressing this critical issue. Based on this, we compared the volcanic activity stages, evolution of geomorphology, and sediment dispersal processes to determine the process of basinal evolution by analyzing the episodes and distribution of volcanic-related deposits, sub-stages, seismic facies, and attributes of deposits of the South Lufeng Sag in the Pearl River Mouth Basin, South China Sea. The widespread development of strong amplitude attributes and chaotic reflection variance cube attribute spatial perspectives reveal the evolution of both intrusive and effusive facies in the lower Wenchang Formation across three stages of volcanic activity. The seismic amplitude difference of the andesite and andesitic tuff unveils the transition of the depositional pathway from north to south in the west depression with change of depocenters, lays the foundation for the dynamic geomorphic evolution of the “transitional basin” in the region. In the middle Huizhou-Lufeng uplift, the chaotic reflection with weak amplitude and obvious diapir structures revealed by andesite constrain the distribution of sedimentary space and the transformation of sedimentary pathways within the basin, and the evolution process of the “restricted basin” is summarised in terms of sedimentary filling processes. The seismic amplitude differences of basalt and andesitic tuff - related sediments in the east depression record the process of transformation from a single sedimentary channel to multi-pathway transport, which is summarised as the evolutionary model of the “diffusive basin”. This study offers a meticulous exploration into the evolutionary trajectory of dynamic geomorphology and sedimentary accumulation in a basin regulated by volcanic activity. The findings pave the way for the extensive application of this methodology in petroleum development across various geographic regions.

Fracture Detection With Azimuthal Seismic Amplitude Difference Inversion in Weakly Monoclinic Medium

The rock with a vertical group of aligned fractures in the tilted transverse isotropy (TTI) background medium is regarded as an effective monoclinic medium. Thomsen parameters and fracture weaknesses can reflect the development degree of TTI background anisotropy and vertical fractures, respectively. Thus, this paper first establishes the approximate stiffness matrix of the monocline medium through the Bond transformation from Thomsen weak anisotropy theory and effective medium theory. Moreover, considering the Born scattering theory, a linearized approximate formula of PP wave reflection coefficient is further deduced. This approximate formula contains the parameters of incident angle, azimuth, tilted angle, compressional and shear moduli, density, fracture weaknesses, and Thomsen parameters. Then, the contribution of each parameter on the reflection coefficient by numerical simulation is analyzed respectively. Finally, from the perspective of Bayesian inference, an azimuthal seismic amplitude difference inversion approach incorporating Cauchy prior information and low-frequency regularization of model parameters is proposed to realize the simultaneous estimation of fracture weaknesses and Thomsen parameters. The synthetic test demonstrates that the inversion approach proposed in this article can obtain information on vertical fractures and TTI background medium and can be applied to azimuthal seismic data with moderate noise well. Furthermore, the inversion results of the synthetic test and field data illustrate the stability and feasibility of the inversion approach and also confirm the fracture weaknesses and Thomsen parameters of the monoclinic medium can be reasonably estimated by the inversion equation derived in this paper.

Joint impedance and facies inversion of time-lapse seismic data for improving monitoring of CO2 incidentally stored from CO2 EOR

Time-lapse seismic monitoring is an effective and proven technology for mapping the distribution of CO2 in a subsurface reservoir. When injected CO2 displaces other reservoir fluids, porous-medium properties are changed and thus the seismic impedance changes, causing time-lapse seismic amplitude differences in the injection zones. The analysis and interpretation of images created from these amplitude differences can provide information about reservoir architecture and the CO2 migration within the reservoir. Incorporating seismic inversion and rock physics into the interpretation of time-lapse seismic data can considerably improve the modeling and monitoring to detect and assess the location of CO2 over time. The joint inversion method presented in this paper has an integral representation of the geology in the inversion algorithm using elastic facies, which provides information about the spatial distribution of the geologic heterogeneities controlling the movement of fluids in the reservoir. The method was successfully applied to time-lapse seismic data from a mature oil field undergoing CO2 enhanced oil recovery. The estimated seismic acoustic impedances and facies reflect the characteristics of individual geologic facies and fluid conditions of the reservoir subject to CO2 injection. The probabilities estimated by the joint impedance and facies inversion for the reservoir's litho-fluid facies can be used for forecasting CO2 saturation and pressure changes within the target reservoir.

Multiscale frequency-domain seismic inversion for fracture weakness

Amplitude variation with offset and azimuth (AVOAz) inversion is an effective tool to invert the azimuthal seismic reflection data for fracture weaknesses, which play an important role in seismic characterization of fractures. Conventional AVOAz inversion is implemented in the time domain, which simultaneously uses full-frequency components of the seismic data causing an unstable and inaccurate inversion result in the case of noisy seismic data. Here we propose a novel multiscale frequency-domain seismic inversion approach to improve resolution and accuracy of fracture weakness estimates. Based on new derived frequency-domain expression of azimuthal seismic amplitude difference for a horizontal transversely isotropic (HTI) medium, we build the kernel function incorporated with the Fourier operator, which avoids the Fourier inverse transform in the frequency-domain inversion. Low frequency information in seismic data is often missing or contaminated with noises, thus we establish an inversion objective function combining low frequency regularization term and Cauchy sparse regularization term in the Bayesian framework. We adopt the multiscale strategy and perform inversion successively from low to high frequency group utilizing a limited number of frequency components with a high signal-to-noise (S/N) ratio. In addition, we compare the multiscale frequency-domain inversion approach, the frequency-domain simultaneous inversion approach, and the time-domain inversion approach using synthetic data and field data. Synthetic example demonstrates that the cross-correlation coefficients (CCs) between the true fracture weaknesses and the inversion results obtained by multiscale frequency-domain inversion approach are above 0.83 even with a S/N of 2. Compared to the time-domain inversion approach and the frequency-domain simultaneous inversion approach, the inversion results with multiscale frequency-domain inversion approach have higher resolution and accuracy. Field data example further validates the feasibility and superiority of the proposed multiscale frequency-domain inversion approach.

Estimating tilted fracture weaknesses from azimuthal differences in seismic amplitude data

Tilted transverse isotropy (TTI) provides a useful model for the elastic response of a medium containing aligned fractures with a symmetry axis oriented obliquely in the vertical and horizontal coordinate directions. Robust methods for determining the TTI properties of a medium from seismic observations to characterize fractures are sought. Azimuthal differencing of seismic amplitude data produces quantities that are particularly sensitive to TTI properties. Based on the linear slip fracture model, we express the TTI stiffness matrix in terms of the normal and tangential fracture weaknesses. Perturbing stiffness parameters to simulate an interface separating an isotropic medium and a TTI medium, we derive a linearized P-to-P reflection coefficient expression in which the influence of tilt angle and fracture weaknesses separately emerge. We formulate a Bayesian inversion approach in which amplitude differences between seismic data along two azimuths, interpreted in terms of the reflection coefficient approximation, are used to determine fracture weaknesses and tilt angle. Tests with simulated data confirm that the unknown parameter vector involving fracture weakness and tilted fracture weaknesses is stably estimated from seismic data containing a moderate degree of additive Gaussian noise. The inversion approach is applied to a field surface seismic data acquired over a fractured reservoir; from it, interpretable tilted fracture weaknesses, consistent with expected reservoir geology, are obtained. We determine that our inversion approach and the established inversion workflow can produce the properties of systems of tilted fractures stably using azimuthal seismic amplitude differences, which may add important information for characterization of fractured reservoirs.

Effects of patch size changes on the time-lapse seismic reflections of highly attenuating reservoirs

Reservoir fluid depletion and injection inevitably induce changes in pore pressure and saturation, leading to a varying fluid patch size and hence perturbations in seismic velocities and observable time-lapse seismic attributes. The patch size, which may exhibit spatial variations, can possess a characteristic size at each scenario, and therefore another variable impacting time-lapse seismic signatures. In this study, we extend previous research efforts of time-lapse seismic interpretation by considering the fluid patch size effect on time-lapse seismic signals to investigate uncertainties in time-lapse seismic observations. We predicted and analyzed the influence of reservoir permeability and gas saturation on seismic acoustic properties, i.e., attenuation and velocity dispersion, reflectivity and phase, on the basis of a generalized White's spherical model for varied patch sizes on millimeters to centimeters. A stratified model consisting of a fluid-saturated sandstone reservoir showing viscoelastic properties sandwiched between two elastic half-spaces is employed, so as to give insights into the impacts of fluid extraction induced changes of velocity dispersion and attenuation, as well as acoustic impedance contrast, on time-lapse seismic reflections. Analysis of time-lapse seismic travel-time and reflection amplitude differences indicates that ignoring the time-dependent patch size behaviour can give rise to underestimation or overestimation of the reservoir fluid saturation and permeability change.

The Seismic Response to Injected Carbon Dioxide: Comparing Observations to Estimates Based Upon Fluid Flow Modeling

AbstractTime‐lapse seismic amplitude differences and travel time shifts, obtained while monitoring enhanced oil recovery at Cranfield, Mississippi, reveal coherent changes that are associated with the injection of carbon dioxide. Rock physics modeling highlights the importance of the oil, brine, and gas content of pore fluids prior to the injection of carbon dioxide. For example, compressional velocity changes due to the injection of carbon dioxide can drop from 300 m/s to less than 100 m/s as the percentage of oil increases from 1% to 50%. Predictions based upon a new technique for modeling wave propagation in a poroelastic medium containing an arbitrary number of fluids, coupled with multicomponent numerical reservoir modeling at Cranfield, reproduce the general pattern of observed seismic amplitude changes and travel time shifts. In particular, time‐lapse amplitude changes suggest a significant and widespread lowering of compressional velocities due to the injection of CO2 into an aquifer bounding the oil rim of the reservoir. It appears that the large‐scale variations in preexisting pore fluid content have a major influence on seismic velocity changes, even in the highly heterogeneous reservoir at Cranfield.

Laboratory Study of Ultrasonic Velocity Variations During CO2 Flooding in Tuscaloosa Sandstone

SummarySurface seismic technology offers a promising technique for monitoring carbon dioxide (CO2) flood fronts during the enhanced-oil-recovery (EOR) process. Changes in the seismic signature have been observed with CO2 flooding, but its quantification with respect to subsurface saturation is still in its infancy. This study is focused on quantifying variation in the seismic parameters (velocity and impedance) as a function of subsurface fluid type and saturation.We present results of a laboratory study in which velocity and density were monitored as the pore fluids (formation brine and oil, and CO2) were replaced sequentially. All the experiments were performed at in-situ pressure conditions on core plugs (Tuscaloosa Sandstone) recovered from a well in a field currently undergoing CO2 flooding. These plugs are characterized as fluvial (quartz ≈87%, clay ≈10%) and distributary channels (quartz ≈75%, clay ≈17%).When dry samples were flooded with brine, a decrease in compressional-wave (P-wave) velocity (≈2%) was observed until 95% saturation of brine was achieved. For the remaining 5% of saturation, the velocity increased by 7 to 12.5%. After attaining 100% brine saturation, oil was pumped to displace the brine until irreducible water saturation was achieved. A linear drop of 3 to 4% in velocity to oil saturation was observed during this step. Thereafter, liquid CO2 was injected to displace the oil/brine system and a drop of 5 to 10% in P-wave velocity was observed. Biot-Gassmann modeling shows good agreement with experimental results for the gas/brine and oil/brine systems, but not for liquid-CO2 flooding.An empirical relationship was derived from the experimental results, and was applied to sonic logs and used for sensitivity analysis of 4D-seismic data. Post-flooded sonic data were compared to a theoretical sonic curve estimated from an empirical and ‘patchy’ model. Also, a significant increase in seismic amplitude difference was observed when CO2 saturation was greater than 50%.

Qualitative time-lapse seismic interpretation of Norne Field to assess challenges of 4D seismic attributes

Interpretation of time-lapse (or 4D) seismic data in terms of reservoir changes due to production posed many challenges in the Norne Field as the field experienced intense production activity from 1997 to 2006. For some segments within the field, fluid movement and pressure changes have approximately the same degree of impact and possibly opposite effects on the seismic data. Moreover, hardening anomalies could be caused by the increase in water saturation or gas going back to solution, while softening anomalies could be related to the increase in pore pressure or the decrease in fluid bulk modulus following the injection of gas. Therefore, for time-lapse seismic analysis to be most effective and less erroneous, different seismic attributes must be addressed to infer reservoir changes caused by production activity such as seismic amplitude and impedance derived by seismic inversion. In the present work, we analyze the challenges of 4D seismic interpretation in the Norne benchmark case. Our study indicates that acoustic impedance differences derived by a 4D model-based inversion provide an increase in vertical resolution compared to standard seismic amplitude differences. We also present a comparison between results of 4D model-based and colored inversions to evaluate the confidence of inversion anomalies. As this is a benchmark case, this study can be considered to enrich the discussions over qualitative and quantitative time-lapse seismic interpretation and to improve reservoir characterization.

Azimuthal Seismic Amplitude Difference Inversion for Fracture Weakness

Fracture weakness prediction is an important task in fractured reservoir analysis. We propose a new method to use seismic amplitude differences between azimuths to estimate the normal and tangential fracture weaknesses under the assumption that the anisotropic perturbation of the reflection coefficient is mainly induced by fractures. We first derive an expression of the reflection coefficient in terms of the normal and tangential fracture weaknesses for the case of an interface separating two fractured media. Then we use the linear fitting method to get the relationship between the two fracture weaknesses, and change the variables to precondition the inversion problem. The Bayesian framework, under the hypothesis of a Cauchy distribution prior information and a Gaussian distribution likelihood function, is employed to construct the objective function, and an initial low-frequency constraint is introduced to the objective function to make the inversion more stable. The conjugate gradient algorithm is adopted to solve the inverse problem. Tests on both synthetic and real data demonstrate that the normal and tangential fracture weaknesses can be estimated reasonably in the case of seismic data containing a moderate noise, and our inversion approach appears to be a stable method for predicting the fracture weaknesses.

Applications of fluid substitution effect analysis on seismic interpretation

The root mean square (RMS) difference of time-lapse seismic amplitudes is routinely used to identify the substituted fluid type in a reservoir during oil field production and recovery. By a time-lapse seismic method, we study the effects of fluid substitution in a physical model, which is an analogy of the three-dimensional inhomogeneous reservoir. For a weak inhomogeneous medium, gas/oil substitution results in positive anomalies in the reservoir layers, and negative anomalies below the bottom of the reservoir layers; while water/oil substitution causes only weak variations in the reservoir layers, but positive anomalies below the bottom of the reservoir layers. For the strong inhomogeneous medium, no matter what kind of fluid substitution (gas/oil or water/oil), there are significant anomalies in seismic amplitude difference attributes both in and below the reservoir layers. Therefore, for weak inhomogeneous media, such as tight sandstone or thin interbedded layers, the RMS amplitude difference attributes can be used to monitor fluid changes and predict the drilling direction; for inhomogeneous medium with karst carves or fractures, it is difficult to accurately determine the distribution of fluids with the RMS amplitude difference attributes.

Bayesian inversion of time‐lapse seismic data for the estimation of static reservoir properties and dynamic property changes

ABSTRACTSeismic conditioning of static reservoir model properties such as porosity and lithology has traditionally been faced as a solution of an inverse problem. Dynamic reservoir model properties have been constrained by time‐lapse seismic data. Here, we propose a methodology to jointly estimate rock properties (such as porosity) and dynamic property changes (such as pressure and saturation changes) from time‐lapse seismic data. The methodology is based on a full Bayesian approach to seismic inversion and can be divided into two steps. First we estimate the conditional probability of elastic properties and their relative changes; then we estimate the posterior probability of rock properties and dynamic property changes. We apply the proposed methodology to a synthetic reservoir study where we have created a synthetic seismic survey for a real dynamic reservoir model including pre‐production and production scenarios. The final result is a set of point‐wise probability distributions that allow us to predict the most probable reservoir models at each time step and to evaluate the associated uncertainty. Finally we also show an application to real field data from the Norwegian Sea, where we estimate changes in gas saturation and pressure from time‐lapse seismic amplitude differences. The inverted results show the hydrocarbon displacement at the times of two repeated seismic surveys.

Time‐lapse pre‐stack seismic data registration and inversion for CO2 sequestration study at Cranfield

ABSTRACTPre‐stack seismic data are indicative of subsurface elastic properties within the amplitude versus offset characteristic and can be used to detect elastic rock property changes caused by injection. We perform time‐lapse pre‐stack 3‐D seismic data analysis for monitoring sequestration at Cranfield. The time‐lapse amplitude differences of Cranfield datasets are found entangled with time‐shifts. To disentangle these two characters, we apply a local‐correlation‐based warping method to register the time‐lapse pre‐stack datasets, which can effectively separate the time‐shift from the time‐lapse seismic amplitude difference without changing the original amplitudes. We demonstrate the effectiveness of our registration method by evaluating the inverted elastic properties. These inverted time‐lapse elastic properties can be reliably used for monitoring plumes.

Time-lapse seismic data registration and inversion for CO2 sequestration study at Cranfield

The time-lapse seismic survey for [Formula: see text] sequestration study at Cranfield can be problematic because of misalignments between time-lapse data sets. Such misalignments can be caused by the seismic data processing workflow and may result in the wrong interpretation of time-lapse seismic amplitude differences. We propose an efficient local-correlation-based warping method of registering the time-lapse poststack data sets, which can align these data sets without changing original amplitudes. Application of our registration method to Cranfield time-lapse data demonstrates its effectiveness in separating time-shift character from seismic amplitude signature. After registration, time-lapse differences show an improved consistency in vertical cross sections and a more localized distribution of difference amplitudes along the horizon, allowing us to apply a high-resolution basis pursuit inversion (BPI) for acoustic impedances. Inversion results show that decreases in acoustic impedances occur mostly at the top of the injection interval, which can be used as an indicator of rock properties to detect a subsurface [Formula: see text] plume.

4D Seismic history matching using information from the flooded zone

We introduce a simplified way of using 4D seismic amplitude differences, without explicit full-physics modelling, in a history matching workflow that includes conditioning to both well production data and flooded-zone patterns derived from time-lapse seismic surveys. This approach reduces the complexity of the integration workflow, and speeds up the integration cycle. Examples from both synthetic and field cases demonstrate the success of the workflow.

Reservoir fluid substitution effects on seismic profile interpretation: A physical modeling experiment

P‐wave seismic surveys are performed on realistic physical models of a reservoir formed of interbedded sand and shale layers and filled with gas, water, and oil. They show characteristic behaviour which can be used to distinguish between fluids, with significant implications for the interpretation of time‐lapse experiments. Discontinuous reflections originate in gas‐filled reservoirs, with widely varying amplitude compared to oil‐ or water‐filled reservoirs. Anomalous changes in seismic amplitude difference attributes for reflections within the reservoir are seen for gas/oil substitution. Oil/water substitution results in only weak variations of reservoir elastic properties, thus amplitude difference attributes may be unsuitable for monitoring changes in oil/water saturation. However, direct differences between the time traces are strong. On time‐lapse sections, strong amplitude difference anomalies do not necessarily correspond to the region where the fluid variations occur; this is significant for monitoring oil field development by water injection.

Seismic inversion tracks in situ combustion: A case study from Balol oil field, India

In situ combustion is one of the approaches used for secondary recovery of heavy oil in which time-lapse seismic data might be used to track the production process. We have analyzed three time-lapse seismic surveys carried out at a time interval of one year during pre- and postcombustion phases of in situ combustion at the Balol field in India. Interpretation of these land time-lapse data using standard seismic amplitude differences in terms of reservoir changes during production and injection can be erroneous. The Balol data, in particular, lacked calibration and had poor repeatability. We have addressed these issues by demonstrating the applicability of independent prestack inversion of baseline and monitor surveys to derive elastic attributes that help to produce clearer images of fluid movement. Independent estimates of wavelets from the baseline and two monitor surveys were used in prestack inversion to estimate acoustic impedance, shear impedance, and Poisson’s ratio. The results show unexpected movement of the thermal front away from the injection wells toward the north and northwest of the injection wells, farther from the production wells. These results have been confirmed by well production data from the field north and northwest of Balol.

Time‐lapse (4-D) seismic monitoring of primary production of turbidite reservoirs at South Timbalier Block 295, offshore Louisiana, Gulf of Mexico

Two seismic surveys acquired over South Timbalier Block 295 field (offshore Louisiana) record significant differences in amplitude that are correlated to hydrocarbon production at multiple reservoir levels. The K8 sand, a solution‐gas‐drive reservoir, shows increases in seismic amplitude associated with gas exsolution. The K40 sand, a water‐drive reservoir, shows decreases in seismic amplitude associated with increases in water saturation. A methodology is presented to optimize the correlation between two seismic surveys after they have been individually processed (poststack) This methodology includes rebinning, crosscorrelation, band‐pass filtering, and cross‐equalization. A statistical approach is developed to characterize the correlation between the seismic surveys. This statistical analysis is used to discriminate seismic amplitude differences that record change in rock and fluid properties from those that could be the result of miscorrelation of the seismic data. Time‐lapse seismic analysis provides an important new approach to imaging hydrocarbon production; it may be used to improve reservoir characterization and guide production decisions.