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1.
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.  相似文献   

2.
Forced imbibition was performed in reservoir sandstone by injecting water into a dry sample. The injection was monitored with X‐ray computed tomography and acoustic acquisition to simultaneously visualize the displacement of the fluid and quantify its presence by calculating saturation and P‐wave velocities. We observed a strong influence when changing the injection rates on the acoustic response. Upon decreasing the injection rate from 5 mL/h to 0.1 mL/h, P‐wave velocities decreased sharply: 100 m/s in 1 h. This behaviour is related to the partially saturated conditions of the sample (76% of saturation) before decreasing the injection rate. The air that is still trapped is free to move due to a decrease of pore pressure that is no longer forced by the higher injection rate. After 1 hour, P‐wave velocities started increasing with small changes in saturation. Stopping injection for 16 hrs decreased saturation by 8% and P‐wave velocities by 100 m/s. Restarting injection at 5 mL/h increased saturation to 76% while P‐wave velocities fluctuated considerably for 2 hrs until they stabilized at 2253 m/s. Through the computed tomography scans we observed a water front advancing through the sample and how its shape changed from a plane to a curve after decreasing the injection rate.  相似文献   

3.
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.  相似文献   

4.
Knowledge about saturation and pressure distributions in a reservoir can help in determining an optimal drainage pattern, and in deciding on optimal well designs to reduce risks of blow‐outs and damage to production equipment. By analyzing time‐lapse PP AVO or time‐lapse multicomponent seismic data, it is possible to separate the effects of production related saturation and pressure changes on seismic data. To be able to utilize information about saturation and pressure distributions in reservoir model building and simulation, information about uncertainty in the estimates is useful. In this paper we present a method to estimate changes in saturation and pressure from time‐lapse multicomponent seismic data using a Bayesian estimation technique. Results of the estimations will be probability density functions (pdfs), giving immediate information about both parameter values and uncertainties. Linearized rock physical models are linked to the changes in saturation and pressure in the prior probability distribution. The relationship between the elastic parameters and the measured seismic data is described in the likelihood model. By assuming Gaussian distributed prior uncertainties the posterior distribution of the saturation and pressure changes can be calculated analytically. Results from tests on synthetic seismic data show that this method produces more precise estimates of changes in effective pressure than a similar methodology based on only PP AVO time‐lapse seismic data. This indicates that additional information about S‐waves obtained from converted‐wave seismic data is useful for obtaining reliable information about the pressure change distribution.  相似文献   

5.
天然气在开发过程中,储层有效压力和含气饱和度均会发生变化,研究有效压力和含气饱和度的变化对地震响应特征的影响,在基于时移地震的剩余气分布预测研究中具有重要意义。天然气和石油的声学性质有着明显的差异,油藏时移地震的研究成果不能直接应用于气藏,因此需要开展气藏的时移地震研究。利用Shapiro模型表征干岩石弹性模量随有效压力的变化,借助Batzle-Wang方程描述流体速度随压力的变化关系,联合Gassmann理论进行流体替代,表征饱和流体岩石速度随含气饱和度的变化,建立了饱和流体岩石速度随有效压力和饱和度变化的岩石物理模型。基于该模型,对不同含气饱和度和不同有效压力下的气藏储层模型进行了多波时移地震叠前振幅变化（AVO）模拟。结果表明多波时移地震AVO技术可以有效地区分有效压力变化和含气饱和度变化,为进一步开展气藏多波时移地震流体监测提供了理论参考依据。   相似文献   

6.
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   

7.
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   

8.
The effect of sub‐core scale heterogeneity on fluid distribution pattern, and the electrical and acoustic properties of a typical reservoir rock was studied by performing drainage and imbibition flooding tests with CO2 and brine in a laboratory. Moderately layered Rothbach sandstone was used as a test specimen. Two core samples were drilled; one perpendicular and the other parallel to the layering to allow injection of fluids along and normal to the bedding plane. During the test 3D images of fluid distribution and saturation levels were mapped by an industrial X‐ray CT‐scanner together with simultaneous measurement of electrical resistivity, ultrasonic velocities as well as amplitudes. The results showed how the layering and the flooding direction influenced the fluid distribution pattern and the saturation level of the fluids. For a given fluid saturation level, the measured changes in the acoustic and electrical parameters were affected by both the fluid distribution pattern and the layering orientation relative to the measurement direction. The P‐wave amplitude and the electrical resistivity were more sensitive to small changes in the fluid distribution patterns than the P‐wave velocity. The change in amplitude was the most affected by the orientation of the layering and the resulting fluid distribution patterns. In some instances the change due to the fluid distribution pattern was higher than the variation caused by the change in CO2 saturation. As a result the Gassmann relation based on ‘uniform' or ‘patchy' saturation pattern was not suitable to predict the P‐wave velocity variation. Overall, the results demonstrate the importance of core‐imaging to improve our understanding of fluid distribution patterns and the associated effects on measured rock‐physics properties.  相似文献   

9.
A method to provide an improved time‐lapse seismic attribute for dynamic interpretation is presented. This is based on the causal link between the time‐lapse seismic response and well production activity taken over time. The resultant image is obtained by computing correlation coefficients between sequences of time‐lapse seismic changes extracted over different time intervals from multiply repeated seismic and identical time sequences of cumulative fluid volumes produced or injected from the wells. Maps of these cross‐correlations show localized, spatially contiguous signals surrounding individual wells or a specific well group. These may be associated with connected regions around the selected well or well group. Application firstly to a synthetic data set reveals that hydraulic compartments may be delineated using this method. A second application to a field data set provides empirical evidence that a connected well‐centric fault block and active geobody can be detected. It is concluded that uniting well data and time‐lapse seismic using our proposed method delivers a new attribute for dynamic interpretation and potential updating of the model for the producing reservoir.  相似文献   

10.
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.  相似文献   

11.
部分饱和孔隙岩石中声波传播数值研究   总被引：27，自引：1，他引：27       下载免费PDF全文
利用基于Biot理论的孔隙弹性介质的高阶交错网格有限差分算法，模拟了具有随机分布特征的多种流体饱和岩石中声波在中心频率分别为25，50，75，100kHz时的声场特点. 对于一个由两种成分（气和水）饱和的岩石模型, 假设含不同流体的孔隙介质随机分布在不同的宏观区域，该区域尺度远小于计算的声波波长；组成模型的两种随机分布介质具有相同的固体骨架参数、渗透率和孔隙度，但分别被具有不同压缩性、密度和黏滞系数特性的水和气饱和. 计算和统计分析结果表明，在两种孔隙成分随机分布的部分饱和条件下纵波速度比较复杂，除骨架参数外，其变化主要依赖于中心频率、各种孔隙成分饱和度及饱和介质的速度. 比较该随机分布模型、Gassmann理论模型和White的“气包”模型，发现三种模型得到的纵波速度和衰减规律有较好的定性对应关系. 其次，按照这种随机计算模型的处理方法，本文还首次计算了一个三种流体成分充填饱和的例子，即岩石模型中的孔隙被水、油和气部分饱和，计算时保持模型含水饱和度不变而只改变含油和含气饱和度. 在这种计算条件下，纵波速度随中心频率呈增大的趋势但有起伏变化. 声场快照显示了各种转换波在多种孔隙成分充填（两种和三种孔隙成分）岩石中的声场特征，复杂的水-油-气界面的非均匀分布对声场有重要影响，纵波能量主要转换形成了较为复杂的多种慢纵波和横波.  相似文献   

12.
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   

13.
A recently developed laboratory method allows for simultaneous imaging of fluid distribution and measurements of acoustic‐wave velocities during flooding experiments. Using a specially developed acoustic sample holder that combines high pressure capacity with good transparency for X‐rays, it becomes possible to investigate relationships between velocity and fluid saturation at reservoir stress levels. High‐resolution 3D images can be constructed from thin slices of cross‐sectional computer‐tomography scans (CT scans) covering the entire rock‐core volume, and from imaging the distribution of fluid at different saturation levels. The X‐ray imaging clearly adds a new dimension to rock‐physics measurements; it can be used in the explanation of variations in measured velocities from core‐scale heterogeneities. Computer tomography gives a detailed visualization of density regimes in reservoir rocks within a core. This allows an examination of the interior of core samples, revealing inhomogeneities, porosity and fluid distribution. This mapping will not only lead to an explanation of acoustic‐velocity measurements; it may also contribute to an increased understanding of the fluid‐flow process and gas/liquid mixing mechanisms in rock. Immiscible and miscible flow in core plugs can be mapped simultaneously with acoustic measurements. The effects of core heterogeneity and experimentally introduced effects can be separated, to clarify the validity of measured velocity relationships.  相似文献   

14.
Hydrocarbon production and fluid injection affect the level of subsurface stress and physical properties of the subsurface, and can cause reservoir‐related issues, such as compaction and subsidence. Monitoring of oil and gas reservoirs is therefore crucial. Time‐lapse seismic is used to monitor reservoirs and provide evidence of saturation and pressure changes within the reservoir. However, relative to background velocities and reflector depths, the time‐lapse changes in velocity and geomechanical properties are typically small between consecutive surveys. These changes can be measured by using apparent displacement between migrated images obtained from recorded data of multiple time‐lapse surveys. Apparent displacement measurements by using the classical cross‐correlation method are poorly resolved. Here, we propose the use of a phase‐correlation method, which has been developed in satellite imaging for sub‐pixel registration of the images, to overcome the limitations of cross‐correlation. Phase correlation provides both vertical and horizontal displacements with a much better resolution. After testing the method on synthetic data, we apply it to a real dataset from the Norne oil field and show that the phase‐correlation method can indeed provide better resolution.  相似文献   

15.
To provide a guide for future deep (<1.5 km) seismic mineral exploration and to better understand the nature of reflections imaged by surface reflection seismic data in two mining camps and a carbonatite complex of Sweden, more than 50 rock and ore samples were collected and measured for their seismic velocities. The samples are geographically from the northern and central parts of Sweden, ranging from metallic ore deposits, meta‐volcanic and meta‐intrusive rocks to deformed and metamorphosed rocks. First, ultrasonic measurements of P‐ and S‐wave velocities at both atmospheric and elevated pressures, using 0.5 MHz P‐ and S‐wave transducers were conducted. The ultrasonic measurements suggest that most of the measured velocities show positive correlation with the density of the samples with an exception of a massive sulphide ore sample that shows significant low P‐ and S‐wave velocities. The low P‐ and S‐wave velocities are attributed to the mineral texture of the sample and partly lower pyrite content in comparison with a similar type sample obtained from Norway, which shows significantly higher P‐ and S‐wave velocities. Later, an iron ore sample from the central part of Sweden was measured using a low‐frequency (0.1–50 Hz) apparatus to provide comparison with the ultrasonic velocity measurements. The low‐frequency measurements indicate that the iron ore sample has minimal dispersion and attenuation. The iron ore sample shows the highest acoustic impedance among our samples suggesting that these deposits are favourable targets for seismic methods. This is further demonstrated by a real seismic section acquired over an iron ore mine in the central part of Sweden. Finally, a laser‐interferometer device was used to analyse elastic anisotropy of five rock samples taken from a major deformation zone in order to provide insights into the nature of reflections observed from the deformation zone. Up to 10% velocity‐anisotropy is estimated and demonstrated to be present for the samples taken from the deformation zone using the laser‐interferometery measurements. However, the origin of the reflections from the major deformation zone is attributed to a combination of anisotropy and amphibolite lenses within the deformation zone.  相似文献   

16.
Low frequencies are necessary in seismic data for proper acoustic impedance imaging and for petrophysical interpretation. Without lower frequencies, images can be distorted leading to incorrect reservoir interpretation and petrophysical predictions. As part of the Foinaven Active Reservoir Management (FARM) project, a Towed Streamer survey and an Ocean Bottom Hydrophone (OBH) survey were shot in both 1995 and 1998. The OBH surveys contain lower frequencies than the streamer surveys, providing a unique opportunity to study the effects that low frequencies have on both the acoustic impedance image along with petrophysical time‐lapse predictions. Artefacts that could easily have been interpreted as high‐resolution features in the streamer data impedance volumes can be distinguished by comparison with the impedance volumes created from the OBH surveys containing lower frequencies. In order to obtain results from the impedance volumes, impedance must be related to saturation. The mixing of exsolved gas, oil and water phases involves using the Reuss (uniform) or Voigt (patchy approximation) mixing laws. The Voigt average is easily misused by assuming that the end‐points correspond to 0% and 100% gas saturation. This implies that the patches are either 0% gas saturation or 100% gas saturation, which is never the case. Here, the distribution of gas as it comes out of solution is assumed to be uniform until the gas saturation reaches a sufficiently high value (critical gas saturation) to allow gas to flow. Therefore, at low gas saturations the distribution is uniform, but at saturations above critical, it is patchy, with patches that range from critical gas saturation to the highest gas saturation possible (1 minus residual oil and irreducible water saturation).  相似文献   

17.
碳酸盐岩孔隙结构类型复杂多样,当地震波经过含有不同孔隙结构的流体饱和岩石后往往会产生不同的波频散和衰减特征,这使得根据波的不同响应特征来推断碳酸盐岩的孔隙结构类型,甚至孔隙流体性质信息成为可能.本文针对白云岩、灰岩以及人工碳酸盐岩样品开展了跨频段（超声+低频）实验测量和理论建模,探索碳酸盐岩的孔隙结构类型和孔隙流体对模量频散和衰减的影响机制.首先根据铸体薄片、扫描电镜的图像对碳酸盐岩样品进行了孔隙结构类型分析,并将样品主要分为裂缝型、裂缝-孔隙型、孔洞型三类,然后测量了相应样品完全饱和流体后在不同围压下的模量频散与衰减.在完全饱和甘油并处于低围压时,裂缝型与孔洞型样品均出现一个衰减峰,分别位于1 Hz与100 Hz附近,而裂缝-孔隙型样品则具有两个衰减峰,一个在1 Hz附近,另一个在100 Hz附近.裂缝型样品（裂缝主导）的衰减峰相比孔洞型样品（中等刚度孔隙主导）对应的衰减峰在低围压下幅度更大,且对围压变化更敏感.在测量数据的基础上,建立了考虑纵横比分布的软孔隙和中等刚度孔隙的喷射流模型,认为该模型能一定程度上解释裂缝型、裂缝-孔隙型、孔洞型三种类型碳酸盐岩在测量频带的频散.以上研究加深了对不同孔隙类型主导的碳酸盐岩储层地震响应特征的认识,对储层预测工作的进一步精细化具有重要意义.  相似文献   

18.
P‐wave data from a time‐lapse 3D OBC survey have been analysed to estimate and interpret azimuthal seismic anisotropy. This is achieved by careful processing to preserve the azimuthal signature. The survey images a major reservoir body in a channelized turbidite field in the Gulf of Mexico. Three distinct and significant anisotropy anomalies are discovered on or around this particular ‘4500‐ft sand’, all of which change intensity but not orientation with hydrocarbon production. These anomalies are distributed along the highest concentration of cumulative sand thickness, with their symmetry axes aligned with the main channel axis. We suspect that this time‐lapse anisotropy could be caused by the alignment of the depositional grain fabric. Theoretical calculation predicts that this mechanism, when combined with fluid‐saturation changes, can generate the observed pattern of behaviour. If further supported by other researchers, this result would indicate that appropriately designed seismic surveys could be a useful tool for palaeo‐direction studies in clastic reservoirs and also a useful constraint for directional permeability in the reservoir flow simulation model.  相似文献   

19.
As seismic data quality improves, time‐lapse seismic data is increasingly being called upon to interpret and predict changes during reservoir development and production. Since pressure change is a major component of reservoir change during production, a thorough understanding of the influence of pore pressure on seismic velocity is critical. Laboratory measurements show that differential pressure (overburden minus fluid pressure) does not adequately determine the actual reservoir conditions. Changes in fluid pressure are found to have an additional effect on the physical properties of rocks. The effective‐stress coefficient n is used to quantify the effect of pore pressure compared to confining pressure on rock properties. However, the current practice in time‐lapse feasibility studies, reservoir‐pressure inversion and pore‐pressure prediction is to assume that n= 1. Laboratory measurements, reported in both this and previous research show that n can be significantly less than unity for low‐porosity rocks and that it varies with porosity, rock texture and wave type. We report the results of ultrasonic experiments to estimate n for low‐porosity sandstones with and without microcracks. Our results show that, for P‐waves, n is as low as 0.4 at a differential pressure of 20 MPa (about 3000 psi) for a low‐porosity sandstone. Thus, in pore‐pressure inversion, an assumption of n= 1 would lead to a 150% underestimation of the pore pressure. Comparison of the effective‐stress coefficient for fractured and unfractured samples suggests that the presence of microfractures increases the sensitivity of P‐wave velocity to pore pressure, and therefore the effective‐stress coefficient. Our results show that the effective‐stress coefficient decreases with the differential pressure, with a higher differential pressure resulting in a lower effective‐stress coefficient. While the effective‐stress coefficient for P‐wave velocity can be significantly less than unity, it is close to one for S‐waves.  相似文献   

20.
We obtain the wave velocities and quality factors of clay‐bearing sandstones as a function of pore pressure, frequency and partial saturation. The model is based on a Biot‐type three‐phase theory that considers the coexistence of two solids (sand grains and clay particles) and a fluid mixture. Additional attenuation is described with the constant‐Q model and viscodynamic functions to model the high‐frequency behaviour. We apply a uniform gas/fluid mixing law that satisfies the Wood and Voigt averages at low and high frequencies, respectively. Pressure effects are accounted for by using an effective stress law. By fitting a permeability model of the Kozeny– Carman type to core data, the model is able to predict wave velocity and attenuation from seismic to ultrasonic frequencies, including the effects of partial saturation. Testing of the model with laboratory data shows good agreement between predictions and measurements.  相似文献   

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