Research note: Seismic attenuation due to wave‐induced fluid flow at microscopic and mesoscopic scales

Wave‐induced fluid flow at microscopic and mesoscopic scales arguably constitutes the major cause of intrinsic seismic attenuation throughout the exploration seismic and sonic frequency ranges. The quantitative analysis of these phenomena is, however, complicated by the fact that the governing physical processes may be dependent. The reason for this is that the presence of microscopic heterogeneities, such as micro‐cracks or broken grain contacts, causes the stiffness of the so‐called modified dry frame to be complex‐valued and frequency‐dependent, which in turn may affect the viscoelastic behaviour in response to fluid flow at mesoscopic scales. In this work, we propose a simple but effective procedure to estimate the seismic attenuation and velocity dispersion behaviour associated with wave‐induced fluid flow due to both microscopic and mesoscopic heterogeneities and discuss the results obtained for a range of pertinent scenarios.     

Fractured reservoirs with fracture corridors

Outcrop studies reveal a common occurrence of tabular zones of significantly‐increased fracture intensity affecting otherwise well‐lithified rocks. These zones, called fracture corridors, can have a profound effect on multi‐phase fluid flow in the subsurface. Using standard geo‐modelling tools, it is possible to generate 3D realizations of reservoirs that contain distributions of such fracture corridors that are consistent with observations, including the vertical frequency in pseudo‐wells inserted into the model at random locations. These models can generate the inputs to flow simulation. The approach adopted here is to run the flow simulations in a single‐porosity representation where the flow effects of fractures are upscaled into equivalent cell‐based properties, preserving a clear spatial relationship between the input geology and the resulting cellular model. The simulated reservoir performance outcomes are very similar to those seen in real oilfields: extreme variability between wells, early water breakthrough, disappointing recoveries and patchy saturation distributions. Thus, a model based on fracture corridors can provide an explanation for the observed flow performance of a suitable field. However, the use of seismics to identify fracture corridors is not an easy task. New work is needed to predict the seismic responses of fracture corridor systems to be able to judge whether it is likely that we can robustly detect and characterize these flow‐significant features adequately.     

When 4D seismic is not applicable: Alternative monitoring scenarios for the Arab-D reservoir in the Ghawar Field

Ghawar, the largest oilfield in the world, produces oil from the Upper Jurassic Arab‐D carbonate reservoir. The high rigidity of the limestone–dolomite reservoir rock matrix and the small contrast between the elastic properties of the pore fluids, i.e. oil and water, are responsible for the weak 4D seismic effect due to oil production. A feasibility study was recently completed to quantify the 4D seismic response of reservoir saturation changes as brine replaced oil. The study consisted of analysing reservoir rock physics, petro‐acoustic data and seismic modelling. A seismic model of flow simulation using fluid substitution concluded that time‐lapse surface seismic or conventional 4D seismic is unlikely to detect the floodfront within the repeatability of surface seismic measurements. Thus, an alternative approach to 4D seismic for reservoir fluid monitoring is proposed. Permanent seismic sensors could be installed in a borehole and on the surface for passive monitoring of microseismic activity from reservoir pore‐pressure perturbations. Reservoir production and injection operations create these pressure or stress perturbations. Reservoir heterogeneities affecting the fluid flow could be mapped by recording the distribution of epicentre locations of these microseisms or small earthquakes. The permanent borehole sensors could also record repeated offset vertical seismic profiling surveys using a surface source at a fixed location to ensure repeatability. The repeated vertical seismic profiling could image the change in reservoir properties with production.     

Seismic characterization of hyperconcentrated flows in a volcanic environment

We present direct observations and monitoring data of a hyperconcentrated flow that occurred along La Lumbre ravine, one of the most active channels of Volcán de Colima in Mexico. Flow properties were inferred from video images and seismic data recorded by a geophone installed outside the channel. We collected flow samples 400 m upstream from the monitoring station and analyzed the variation of sediment concentration and grain‐size distribution over time. A joint analysis of hydrological (i.e. flow velocity, wetted perimeter) and rheological (i.e. yield stress τ_y and dynamic viscosity μ_m ) parameters was performed to characterize the flow. Different flow regimes and sediment transport processes were identified and analyzed in comparison with both the amplitude and spectral features of the seismic signal. We observed differing sediment concentrations at the same discharge, suggesting a decoupling between sediment transport processes and discharge for low‐magnitude flows. A straightforward correlation was found between the amplitude of the seismic signal and the sediment concentration, and a value of 1.8 × 10^?3 mm/s was identified that can be used as a threshold to recognize the hyperconcentrated phase of the flow. This information was tested on the complete seismic dataset gathered at La Lumbre ravine during the 2015 rainy season. We identified the transition from streamflow to hyperconcentrated flow (and/or vice versa) in 16 low‐magnitude events and we validated this result using the video recordings. The correlation between seismic amplitude and sediment concentration is valid at La Lumbre ravine but would need to be tested in other locations for the development of automatic flow classification methods. This work contributes to standardized seismic methods for characterizing flow processes in volcanic environments, also for the development of lahar early warning systems. Copyright © 2018 John Wiley & Sons, Ltd.     

Scale effects on modelling the seismic signature of gas: results from an outcrop analogue

Numerous examples of reservoir fields from continental and marine environments involve thin‐bedded geology, yet, the inter‐relationship between thin‐bedded geology, fluid flow and seismic wave propagation is poorly understood. In this paper, we explore the 4D seismic signature due to saturation changes of gas within thin layers, and address the challenge of identifying the relevant scales and properties, which correctly define the geology, fluid flow and seismic wave propagation in the field. Based on the study of an outcrop analogue for a thin‐bedded turbidite, we model the time‐lapse seismic response to fluid saturation changes for different levels of model scale, and explore discrepancies in quantitative seismic attributes caused by upscaling. Our model reflects the geological complexity associated with thin‐bedded turbidites, and its coupling to fluid flow, which in turn affects the gas saturation distribution in space, and its time‐lapse seismic imprint. Rock matrix and fluid properties are modelled after selected fields to reproduce representative field models with realistic impedance contrasts. In addition, seismic modelling includes multiples, in order to assess their contribution in seismic propagation through thin gas layers. Our results show that multiples could contribute significantly to the measured amplitudes in the case of thin‐bedded geology. This suggests that forward/inverse modelling involving the flow simulation and seismic domains used in time‐lapse seismic interpretation should account for thin layers, when these are present in the geological setting.     

Quantitative estimation of water storage and residence time in the epikarst with time‐lapse refraction seismic

The hydrodynamic characterization of the epikarst, the shallow part of the unsaturated zone in karstic systems, has always been challenging for geophysical methods. This work investigates the feasibility of coupling time‐lapse refraction seismic data with petrophysical and hydrologic models for the quantitative determination of water storage and residence time at shallow depth in carbonate rocks. The Biot–Gassmann fluid substitution model describing the seismic velocity variations with water saturation at low frequencies needs to be modified for this lithology. I propose to include a saturation‐dependent rock‐frame weakening to take into account water–rock interactions. A Bayesian inversion workflow is presented to estimate the water content from seismic velocities measured at variable saturations. The procedure is tested first with already published laboratory measurements on core samples, and the results show that it is possible to estimate the water content and its uncertainty. The validated procedure is then applied to a time‐lapse seismic study to locate and quantify seasonal water storage at shallow depth along a seismic profile. The residence time of the water in the shallow layers is estimated by coupling the time‐lapse seismic measurements with rainfall chronicles, simple flow equations, and the petrophysical model. The daily water input computed from the chronicles is used to constraint the inversion of seismic velocities for the daily saturation state and the hydrodynamic parameters of the flow model. The workflow is applied to a real monitoring case, and the results show that the average residence time of the water in the epikarst is generally around three months, but it is only 18 days near an infiltration pathway. During the winter season, the residence times are three times shorter in response to the increase in the effective rainfall.     

Seismic attenuation and velocity dispersion in fractured rocks: The role played by fracture contact areas

The presence of fractures in fluid‐saturated porous rocks is usually associated with strong seismic P‐wave attenuation and velocity dispersion. This energy dissipation can be caused by oscillatory wave‐induced fluid pressure diffusion between the fractures and the host rock, an intrinsic attenuation mechanism generally referred to as wave‐induced fluid flow. Geological observations suggest that fracture surfaces are highly irregular at the millimetre and sub‐millimetre scale, which finds its expression in geometrical and mechanical complexities of the contact area between the fracture faces. It is well known that contact areas strongly affect the overall mechanical fracture properties. However, existing models for seismic attenuation and velocity dispersion in fractured rocks neglect this complexity. In this work, we explore the effects of fracture contact areas on seismic P‐wave attenuation and velocity dispersion using oscillatory relaxation simulations based on quasi‐static poroelastic equations. We verify that the geometrical and mechanical details of fracture contact areas have a strong impact on seismic signatures. In addition, our numerical approach allows us to quantify the vertical solid displacement jump across fractures, the key quantity in the linear slip theory. We find that the displacement jump is strongly affected by the geometrical details of the fracture contact area and, due to the oscillatory fluid pressure diffusion process, is complex‐valued and frequency‐dependent. By using laboratory measurements of stress‐induced changes in the fracture contact area, we relate seismic attenuation and dispersion to the effective stress. The corresponding results do indeed indicate that seismic attenuation and phase velocity may constitute useful attributes to constrain the effective stress. Alternatively, knowledge of the effective stress may help to identify the regions in which wave induced fluid flow is expected to be the dominant attenuation mechanism.     

Regularized tomographic inversion with geological constraints

Reflection tomography is the industry standard tool for velocity model building, but it is also an ill‐posed inverse problem as its solution is not unique. The usual way to obtain an acceptable result is to regularize tomography by feeding the inversion with some a priori information. The simplest regularization forces the solution to be smooth, implicitly assuming that seismic velocity exhibits some degree of spatial correlation. However, velocity is a rock property; thus, the geometry and structure of rock formations should drive correlation in velocity depth models. This observation calls for constraints driven by geological models. In this work, we present a set of structural constraints that feed reflection tomography with geometrical information. These constraints impose the desired characteristics (flatness, shape, position, etc.) on imaged reflectors but act on the velocity update. Failure to respect the constraints indicates either velocity inaccuracies or wrong assumptions concerning the constraints. Reflection tomography with structural constraints is a flexible framework that can be specialized in order to achieve different goals: among others, to flatten the base of salt bodies or detachment surfaces, to recover the horizontalness of oil–water contacts, or to impose the co‐location of the same imaged horizon between PP and PS images. The straightforward application of structural constraints is that of regularizing tomography through geological information, particularly at the latest stages of the depth imaging workflow, when the depth migration structural setting reached a consistent geological interpretation. Structural constraints are also useful in minimizing the well‐to‐seismic mis‐ties. Moreover, they can be used as a tool to check the consistency of interpreters' hypothesis with seismic data. Indeed, inversion with structural constraints will preserve image focusing only if the interpreters' insights are consistent with the data. Results from synthetic and real data demonstrate the effectiveness of reflection tomography with structural constraints.     

Seismic attenuation in Faroe Islands basalts

We analysed vertical seismic profiling (VSP) data from two boreholes at Glyvursnes and Vestmanna on the island of Streymoy, Faroe Islands, to determine the magnitude and causes of seismic attenuation in sequences of basalt flows. The work is part of SeiFaBa, a major project integrating data from vertical and offset VSP, surface seismic surveys, core samples and wireline log data from the two boreholes. Values of effective seismic quality factor (Q) obtained at Glyvursnes and Vestmanna are sufficiently low to significantly degrade the quality of a surface reflection seismic image. This observation is consistent with results from other VSP experiments in the North Atlantic region. We demonstrate that the most likely cause of the low values of effective Q at Glyvursnes and Vestmanna is a combination of 1D scattering and intrinsic attenuation due to seismic wave‐induced fluid flow within pores and micro‐cracks. Tests involving 3D elastic wave numerical modelling with a hypothetical basalt model based on field observations, indicate that little scattering attenuation is caused by lateral variations in basalt structure.     

Quantitative imaging of complex structures from dense wide-aperture seismic data by multiscale traveltime and waveform inversions: a case study

An integrated multiscale seismic imaging flow is applied to dense onshore wide‐aperture seismic data recorded in a complex geological setting (thrust belt). An initial P‐wave velocity macromodel is first developed by first‐arrival traveltime tomography. This model is used as an initial guess for subsequent full‐waveform tomography, which leads to greatly improved spatial resolution of the P‐wave velocity model. However, the application of full‐waveform tomography to the high‐frequency part of the source bandwidth is difficult, due to the non‐linearity of this kind of method. Moreover, it is computationally expensive at high frequencies since a finite‐difference method is used to model the wave propagation. Hence, full‐waveform tomography was complemented by asymptotic prestack depth migration to process the full‐source bandwidth and develop a sharp image of the short wavelengths. The final traveltime tomography model and two smoothed versions of the final full‐waveform tomography model were used as a macromodel for the prestack depth migration. In this study, wide‐aperture multifold seismic data are used. After specific preprocessing of the data, 16 frequency components ranging from 5.4 Hz to 20 Hz were inverted in cascade by the full‐waveform tomography algorithm. The full‐waveform tomography successfully imaged SW‐dipping structures previously identified as high‐resistivity bodies. The relevance of the full‐waveform tomography models is demonstrated locally by comparison with a coincident vertical seismic profiling (VSP) log available on the profile. The prestack depth‐migrated images, inferred from the traveltime, and the smoothed full‐waveform tomography macromodels are shown to be, on the whole, consistent with the final full‐waveform tomography model. A more detailed analysis, based on common‐image gather computations, and local comparison with the VSP log revealed that the most accurate migrated sections are those obtained from the full‐waveform tomography macromodels. A resolution analysis suggests that the asymptotic prestack depth migration successfully migrated the wide‐aperture components of the data, allowing medium wavelengths in addition to the short wavelengths of the structure to be imaged. The processing flow that we applied to dense wide‐aperture seismic data is shown to provide a promising approach, complementary to more classical seismic reflection data processing, to quantitative imaging of complex geological structures.     

Anisotropic permeability in fractured reservoirs from frequency‐dependent seismic Amplitude Versus Angle and Azimuth data

Attempts have previously been made to predict anisotropic permeability in fractured reservoirs from seismic Amplitude Versus Angle and Azimuth data on the basis of a consistent permeability‐stiffness model and the anisotropic Gassmann relations of Brown and Korringa. However, these attempts were not very successful, mainly because the effective stiffness tensor of a fractured porous medium under saturated (drained) conditions is much less sensitive to the aperture of the fractures than the corresponding permeability tensor. We here show that one can obtain information about the fracture aperture as well as the fracture density and orientation (which determines the effective permeability) from frequency‐dependent seismic Amplitude Versus Angle and Azimuth data. Our workflow is based on a unified stiffness‐permeability model, which takes into account seismic attenuation by wave‐induced fluid flow. Synthetic seismic Amplitude Versus Angle and Azimuth data are generated by using a combination of a dynamic effective medium theory with Rüger's approximations for PP reflection coefficients in Horizontally Transversely Isotropic media. A Monte Carlo method is used to perform a Bayesian inversion of these synthetic seismic Amplitude Versus Angle and Azimuth data with respect to the parameters of the fractures. An effective permeability model is then used to construct the corresponding probability density functions for the different components of the effective permeability constants. The results suggest that an improved characterization of fractured reservoirs can indeed be obtained from frequency‐dependent seismic Amplitude Versus Angle and Azimuth data, provided that a dynamic effective medium model is used in the inversion process and a priori information about the fracture length is available.     

Probabilistic seismic loss assessment of aging bridges using a component‐level cost estimation approach

Deteriorating highway bridges in the United States and worldwide have demonstrated susceptibility to damage in earthquake events, with considerable economic consequences due to repair or replacement. Current seismic loss assessment approaches for these critical elements of the transportation network neglect the effects of aging and degradation on the loss estimate. However, the continued aging and deterioration of bridge infrastructure could not only increase susceptibility to seismic damage, but also have a significant impact on these economic losses. Furthermore, the contribution of individual aging components to system‐level losses, correlations between these components, and uncertainty modeling in the risk assessment and repair modeling are all crucial considerations to enhance the accuracy and confidence in bridge loss estimates. In this paper, a new methodology for seismic loss assessment of aging bridges is introduced based on the non‐homogeneous Poisson process. Statistical moments of seismic losses can be efficiently estimated, such as the expected value and variance. The approach is unique in its account for time‐varying seismic vulnerability, uncertainty in component repair, and the contribution of multiple correlated aging components. A representative case study is presented with two fundamentally distinct highway bridges to demonstrate the effects of corrosion deterioration of different bridge components on the seismic losses. Using the proposed model, a sensitivity study is also conducted to assess the effect of parameter variations on the expected seismic losses. The results reveal that the seismic losses estimated by explicitly considering the effects of deterioration of bridge components is significantly higher than that found by assuming time‐invariant structural reliability. Copyright © 2011 John Wiley & Sons, Ltd.     

Quantitative integration of 3D and 4D seismic impedance into reservoir simulation model updating in the Norne Field

The ultimate goal of reservoir simulation in reservoir surveillance technology is to estimate long-term production forecasting and to plan development and management of petroleum fields. However, maintaining reliable reservoir models which honour available static and dynamic data, involve inherent risks due to the uncertainties in space and time of the distribution of hydrocarbons inside reservoirs. Recent applications have shown that these uncertainties can be reduced by quantitative integration of seismic data into the reservoir modelling workflows to identify which areas and reservoir attributes of the model should be updated. This work aims using seismic data to reduce ambiguity in calibrating reservoir flow simulation model with an uncertain petro-elastic model, proposing a circular workflow of inverted seismic impedance (3D and 4D) and engineering studies, with emphasis on the interface between static and dynamic models. The main contribution is to develop an updating procedure for adjusting reservoir simulation response before using it in the production forecasting and enhance the interpretive capability of reservoir properties. Accordingly, the workflow evaluates consistency of reservoir simulation model and inverted seismic impedance, assisted by production history data, to close the loop between reservoir engineering and seismic domains. The methodology is evaluated in a complex, faulted, sandstone reservoir, the Norne benchmark field, where a significant reservoir behaviour understanding (about the static and dynamic reservoir properties) is obtained towards the quantitative integration of seismic impedance data. This leads to diagnosis of the reservoir flow simulation reliability and generation of an updated simulation model consistent with observed seismic and well production history data, as well as a calibrated petro-elastic model. Furthermore, as Norne Field is a benchmark case, this study can be considered to enrich the discussions over deterministic or probabilistic history matching studies.     

Markovian modeling of seismic damage accumulation

Analysis of civil structures at the scale of life‐cycle requires stochastic modeling of degradation. Phenomena causing structures to degrade are typically categorized as aging and point‐in‐time overloads. Earthquake effects are the members of the latter category this study deals with in the framework of performance‐based earthquake engineering (PBEE). The focus is structural seismic reliability, which requires modeling of the stochastic process describing damage progression, because of subsequent events, over time. The presented study explicitly addresses this issue via a Markov‐chain‐based approach, which is able to account for the change in seismic response of damaged structures (i.e. state‐dependent seismic fragility) as well as uncertainty in occurrence and intensity of earthquakes (i.e. seismic hazard). The state‐dependent vulnerability issue arises when the seismic hysteretic response is evolutionary and/or when the damage measure employed is such that the degradation increment probabilistically depends on the conditions of the structure at the time of the shock. The framework set up takes advantage also of the hypotheses of classical probabilistic seismic hazard analysis, allowing to separate the modeling of the process of occurrence of seismic shocks and the effect they produce on the structure. It is also discussed how the reliability assessment, which is in closed‐form, may be virtually extended to describe a generic age‐ and state‐dependent degradation process (e.g. including aging and/or when aftershock risk is of interest). Illustrative applications show the options to calibrate the model and its potential in the context of PBEE. Copyright © 2015 John Wiley & Sons, Ltd.     

Overburden complexity and repeatability of seismic data: Impacts of positioning errors at the Oseberg field, North Sea

Repeatability of seismic data plays a crucial role in time‐lapse seismic analysis. There are several factors that can decrease the repeatability, such as positioning errors, varying tide, source variations, velocity changes in the water layer (marine data) and undesired effects of various processing steps. In this work, the complexity of overburden structure, as an inherent parameter that can affect the repeatability, is studied. A multi‐azimuth three‐dimensional vertical‐seismic‐profiling data set with 10 000 shots is used to study the relationship between overburden structure and repeatability of seismic data. In most repeatability studies, two data sets are compared, but here a single data set has been used because a significant proportion of the 10 000 shots are so close to each other that a repeatability versus positioning error is possible. We find that the repeatability decreases by a factor of approximately 2 under an overburden lens. Furthermore, we find that the X‐ and Y‐components have approximately the same sensitivity to positioning errors as the Z‐component (for the same events) in this three‐dimensional vertical‐seismic‐profiling experiment. This indicates that in an area with complex overburden, positioning errors between monitor and base seismic surveys are significantly more critical than outside such an area. This study is based on a three‐dimensional three‐component vertical‐seismic‐profiling data set from a North Sea reservoir and care should be taken when extrapolating these observations into a general four‐dimensional framework.     

Geostatistical seismic inversion for non‐stationary patterns using direct sequential simulation and co‐simulation

Geostatistical seismic inversion methods are routinely used in reservoir characterisation studies because of their potential to infer the spatial distribution of the petro‐elastic properties of interest (e.g., density, elastic, and acoustic impedance) along with the associated spatial uncertainty. Within the geostatistical seismic inversion framework, the retrieved inverse elastic models are conditioned by a global probability distribution function and a global spatial continuity model as estimated from the available well‐log data for the entire inversion grid. However, the spatial distribution of the real subsurface elastic properties is complex, heterogeneous, and, in many cases, non‐stationary since they directly depend on the subsurface geology, i.e., the spatial distribution of the facies of interest. In these complex geological settings, the application of a single distribution function and a spatial continuity model is not enough to properly model the natural variability of the elastic properties of interest. In this study, we propose a three‐dimensional geostatistical inversion technique that is able to incorporate the reservoir's heterogeneities. This method uses a traditional geostatistical seismic inversion conditioned by local multi‐distribution functions and spatial continuity models under non‐stationary conditions. The procedure of the proposed methodology is based on a zonation criterion along the vertical direction of the reservoir grid. Each zone can be defined by conventional seismic interpretation, with the identification of the main seismic units and significant variations of seismic amplitudes. The proposed method was applied to a highly non‐stationary synthetic seismic dataset with different levels of noise. The results of this work clearly show the advantages of the proposed method against conventional geostatistical seismic inversion procedures. It is important to highlight the impact of this technique in terms of higher convergence between real and inverted reflection seismic data and the more realistic approximation towards the real subsurface geology comparing with traditional techniques.     

基于应变率场的全球地震活动特征模拟探索

本文提出利用全球应变率资料模拟全球地震活动特征的基本思想, 并作了初步探索。 利用GSRM的全球应变率场结果, 初步设计了模拟全球地震活动时空分布特征的细胞自动机模型。 该模型把地球考虑为一个自组织的整体系统, 制定了细胞自动机的演化规则, 获得了模拟的人工地震目录。 初步的模拟结果基本反映了全球地震活动的主要分布特征, 体现了全球构造活动强弱的主要格局, 初步达到了利用GPS等实测资料计算的应变率作为细胞自动机网格状态及其改变量来模拟复杂的全球地震活动特征的实验目的。     

青藏高原东南缘热流估算及与地震活动相关性分析

青藏高原东南缘地区内部构造运动强烈,是地热资源发育与地震事件频发的活动地区.大地热流记录了发生在地球深部各种作用过程的热学信息,可以作为地质构造活动和地震活动研究的有效约束,但是大范围的热流数据测量很难实现,因此,本文根据居里面深度结合放射性元素分布等计算了青藏高原东南缘的大地热流分布.首先,通过地表放射性元素的分布计算出地表产热量的分布,然后,利用相关地热参数之间的关系迭代计算出该地区地壳上下层的热导率分布,最终估算出地表热流及地下不同深度处热流值的分布.本文结果表明:(1)青藏高原东南缘的大地热流位于44～108mW·m~(-2)之间,平均75mW·m~(-2),符合研究地区西南高、东北低的背景趋势,地壳内部热流值随深度的增加而降低.大部分地区地表热流异常与实际地热带分布相吻合,如川西、藏东南与滇西地区等地为地热高值区,川东和楚雄等地为热流低值区.(2)结合其他地球物理探测结果,总结了地壳内部热流与地震事件的联系:在地热梯度带地区,当两侧地层在一定深度范围内存在明显物性差异时,地震事件高发.     

Effect of fracture fill on frequency‐dependent anisotropy of fractured porous rocks

In fractured reservoirs, seismic wave velocity and amplitude depend on frequency and incidence angle. Frequency dependence is believed to be principally caused by the wave‐induced flow of pore fluid at the mesoscopic scale. In recent years, two particular phenomena, i.e., patchy saturation and flow between fractures and pores, have been identified as significant mechanisms of wave‐induced flow. However, these two phenomena are studied separately. Recently, a unified model has been proposed for a porous rock with a set of aligned fractures, with pores and fractures filled with two different fluids. Existing models treat waves propagating perpendicular to the fractures. In this paper, we extend the model to all propagation angles by assuming that the flow direction is perpendicular to the layering plane and is independent of the loading direction. We first consider the limiting cases through poroelastic Backus averaging, and then we obtain the five complex and frequency‐dependent stiffness values of the equivalent transversely isotropic medium as a function of the frequency. The numerical results show that, when the bulk modulus of the fracture‐filling fluid is relatively large, the dispersion and attenuation of P‐waves are mainly caused by fractures, and the values decrease as angles increase, almost vanishing when the incidence angle is 90° (propagation parallel to the fracture plane). While the bulk modulus of fluid in fractures is much smaller than that of matrix pores, the attenuation due to the “partial saturation” mechanism makes the fluid flow from pores into fractures, which is almost independent of the incidence angle.