Seismic characterization of reservoirs containing multiple fracture sets

Natural fractures in reservoirs play an important role in determining fluid flow during production and knowledge of the orientation and density of fractures is required to optimize production. Variations in reflection amplitude versus offset (AVO) are sensitive to the presence of fractures but current models used to invert the seismic response often make simplified assumptions that prevent fractured reservoirs from being characterized correctly. For example, many models assume a single set of perfectly aligned fractures, whereas most reservoirs contain several fracture sets with variable orientation within a given fracture set. In addition, many authors only consider the azimuthal variation in the small offset amplitude versus offset and azimuth response (the variation in AVO gradient with azimuth), while the effect of fractures on amplitude versus offset and azimuth increases with increasing offset. In this paper, the variation in the reflection coefficient of seismic P -waves as a function of azimuth and offset due to the presence of multiple sets of fractures with variable orientation within any fracture set is used to determine the components of a second-rank fracture compliance tensor  α _ij   . The variation in the trace of this tensor as a function of position in the reservoir can be used to estimate the variation in fracture density with position in the reservoir and may be used to choose the location of infill wells in the field. The principal axes of  α _ij   reveal the most compliant direction within the reservoir and may be used to optimize the trajectory of deviated wells. The determination of the principal axes of  α _ij   requires wide azimuth acquisition and the use of the small-offset amplitude versus offset and azimuth (the azimuthal variation of the AVO gradient) may give misleading results.     

HTI介质中的反射纵波方位属性

利用横波响应进行裂缝性各向异性介质的检测在实际应用中取得了很好的效果,但技术复杂、成本较高使该方法的广泛使用受到限制,而纵波资料采集和处理技术的精细有效保持了纵波的各种属性,这为直接利用纵波资料进行裂缝检测创造了条件.地下垂直定向裂缝通常用HTI介质模型来描述,为此,本文利用射线追踪和反射率法计算了层状各向同性介质背景下的HTI介质顶、底界面的反射纵波旅行时和反射系数,并分析了这些属性随观测方位的变化规律.研究表明,HTI介质底界面反射纵波旅行时和HTI介质顶界面反射系数表现出了明显的方位各向异性;旅行时、振幅和AVO梯度属性均在0°观测方位和90°观测方位上存在最大差异,可以用多种属性联合来精确判定裂缝的发育方向.     

Azimuth-dependent AVO in reservoirs containing non-orthogonal fracture sets

Azimuthal anisotropy in rocks can result from the presence of one or more sets of partially aligned fractures with orientations determined by the stress history of the rock. The symmetry of a rock with horizontal bedding that contains two or more non-orthogonal sets of vertical fractures may be approximated as monoclinic with a horizontal plane of mirror symmetry. For offsets that are small compared with the depth of the reflector, the azimuthal variation in P-wave AVO gradient for such a medium varies with azimuth as     where φ is the azimuth measured with respect to the fast polarization direction for a vertically polarized shear wave. φ ₂ depends on both the normal compliance B _N and the shear compliance B _T of the fractures and may differ from zero if B _N B _T varies significantly between fracture sets. If B _N B _T is the same for all fractures,     and the principal axes of the azimuthal variation in P-wave AVO for fixed offset are determined by the polarization directions of a vertically propagating shear wave. At larger offsets, terms in     and     are required to describe the azimuthal variation in AVO accurately. φ ₄ and φ ₆ also depend on B _N B _T. For gas-filled open fractures     but a lower value of B _N B _T may result from the presence of a fluid with non-zero bulk modulus.     

Sensitivity of reflection seismic data to oil-column height in high-porosity sandstones

Tuning is the effect of interference between the reflections from the top and bottom of a thin layer on the amplitude of the composite reflection. For a homogeneous sandstone reservoir containing an oil column overlying brine, interference between the reflection from the top reservoir and the oil/water contact is a function of the height of the oil column. If the properties of the sandstone do not vary across the oil/water contact, the SS, PS and SP reflection coefficients from the oil/water contact are small in comparison to the PP reflection coefficient. This allows analytic expressions for the effective PP and PS reflection coefficients from the reservoir to be derived that include all P‐wave multiples within the oil column. For a given source/receiver offset, the component of the wavevector inside the oil column normal to the interface is larger for the PPPP reflection than for the PPPS reflection, due to the asymmetry in the raypath for the PPPS reflection. The PPPS reflection is therefore useful for determining oil‐column heights larger than that discriminated by the PPPP reflection, especially when used at wider offsets. A convenient classification of the AVO response of hydrocarbon‐bearing sandstone reservoirs overlain by shale is the scheme of Rutherford and Williams. Class 1 sands have higher acoustic impedance for normal incidence than the overlying shale, Class 2 sands have nearly the same acoustic impedance as the shale and Class 3 sands have lower acoustic impedance. Synthetic shot gathers calculated for these three classes as a function of oil‐column height show that a combination of the PPPP and the PPPS amplitudes can be plotted as a tuning trajectory, which can be used to determine the oil‐column height. This method is most sensitive for reservoirs that belong to AVO classes 1 and 2, and therefore may be useful in AVO analysis of Class 1 and 2 reservoirs where the traditional AVO indicators (developed for Class 3 reservoirs) do not work very well. These results demonstrate the usefulness of shear waves recorded in the marine environment at wide offsets.     

Anisotropic P-wave attenuation measured from a multi-azimuth surface seismic reflection survey

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⁻¹_eff 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⁻¹_eff= 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⁻¹_eff= 52 ± 15) and slowest stacking velocity. The variation of Q⁻¹_eff with azimuth φ is well fitted by 1000Q⁻¹_eff = 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.     

Effects of pore fluid pressure on the seismic response of a fractured carbonate reservoir

An effective medium model for the stress-dependent seismic properties of fractured reservoirs is developed here on the basis of a combination of a general theory of viscoelastic waves in rock-like composites with recently published formulae for deformation of communicating and interacting cavities (interconnected pores/cracks and fractures at finite concentration) under drained loading. The inclusion-based model operates with spheroidal cavities at two different length scales; namely, the microscopic scale of the pores and (grain-boundary) cracks, and the mesoscopic scale of the fractures (controlling the flow of fluid). The different cavity types can in principle have any orientation and aspect ratio, but the microscopic pores/cracks and mesoscopic fractures were here assumed to be randomly and vertically oriented, respectively. By using three different aspect ratios for the relatively round pores (representing the stiff part of the pore space) and a distribution of aspect ratios for the relatively flat cracks (representing the compliant part of the pore space), we obtained a good fit between theoretical predictions and ultrasonic laboratory measurements on an unfractured rock sample under dry conditions. By using a single aspect ratio for the mesoscopic fractures, we arrived at a higher-order microstructural model of fractured porous media which represents a generalization of the first-order model developed by Chapman et al. (2002,2003). The effect of cavity size was here modelled under the assumption that the characteristic time for wave-induced (squirt) flow at the scale of a particular cavity (pore/crack vs. fracture) is proportional with the relevant scale-size. In the modelling, we investigate the effect of a decreasing pore pressure with constant confining pressure (fixed depth), and hence, increasing effective pressure. The analysis shows that the attenuation-peak due to the mesoscopic fractures in the reservoir will move downward in frequency as the effective pressure increases. In the range of seismic frequencies, our modelling indicates that the P-wave velocities may change by more than 20% perpendicular to the fractures and close to 10% parallel to the fractures. In comparison, the vertical S-wave velocities change by only about 5% for both polarization directions (perpendicular and parallel to the fractures) when the effective pressure increases from 0 to 15 MPa. This change is mainly due to the overall change in porosity with pressure. The weak pressure dependence is a consequence of the fact that the S waves will only sense if the fractures are open or not, and since all the fractures have the same aspect ratio, they will close at the same effective pressure (which is outside the analysed interval). Approximate reflection coefficients were computed for a model consisting of the fractured reservoir embedded as a layer in an isotropic shale and analysed with respect to variations in Amplitude Versus Offset and aZimuth (AVOZ) properties at seismic frequencies for increasing effective pressure. For the P-P reflections at the top of the reservoir, it is found that there is a significant dependence on effective pressure, but that the variations with azimuth and offset are small. The lack of azimuthal dependence may be explained from the approximate reflection coefficient formula as a result of cancellation of terms related to the S-wave velocity and the Thomson’s anisotropy parameter δ. For the P-S reflection, the azimuthal dependence is larger, but the pressure dependence is weaker (due to a single aspect ratio for the fractures). Finally, using the effective stiffness tensor for the fractured reservoir model with a visco-elastic finite-difference code, synthetic seismograms and hodograms were computed. From the seismograms, attenuation changes in the P wave reflected at the bottom of the reservoir can be observed as the effective pressure increases. S waves are not much affected by the fractures with respect to attenuation, but azimuthal dependence is stronger than for P waves, and S-wave splitting in the bottom reservoir P-S reflection is clearly seen both in the seismograms and hodograms. From the hodograms, some variation in the P-S reflection with effective pressure can also be observed.     

Fracture characterization using converted waves

We present a method for inversion of fracture compliance matrix components from wide‐azimuth noisy synthetic PS reflection data and quantitatively show that reflection amplitude variations with offset and azimuth for converted PS‐waves are more informative than P‐waves for fracture characterization. We consider monoclinic symmetry for fractured reservoir (parameters chosen from Woodford Shale), which can be formed by two or more sets of vertical fractures embedded in a vertically transverse isotropic background. Components of effective fracture compliance matrices for a medium with monoclinic symmetry are related to the characteristics of the fractured medium. Monte Carlo simulation results show that inversion of PS reflection data is more robust than that of PP reflection data to uncertainties in our a priori knowledge (vertically transverse isotropic parameters of unfractured rock) than PP reflection data. We also show that, while inversion of PP reflections is sensitive to contrasts in elastic properties of upper and lower media, inversion of PS reflections is robust with respect to such contrasts.     

Bayesian seismic inversion for estimating fluid content and fracture parameters in a gas-saturated fractured porous reservoir

Understanding the effects of in situ fluid content and fracture parameters on seismic characteristics is important for the subsurface exploration and production of fractured porous rocks. The ratio of normal-to-shear fracture compliance is typically utilized as a fluid indicator to evaluate anisotropy and identify fluids filling the fractures, but it represents an underdetermined problem because this fluid indicator varies as a function of both fracture geometry and fluid content. On the bases of anisotropic Gassmann's equation and linear-slip model, we suggest an anisotropic poroelasticity model for fractured porous reservoirs. By combining a perturbed stiffness matrix and asymptotic ray theory, we then construct a direct relationship between the PP-wave reflection coefficients and characteristic parameters of fluids(P-and S-wave moduli) and fractures(fracture quasi-weaknesses), thereby decoupling the effects of fluid and fracture properties on seismic reflection characterization.By incorporating fracture quasi-weakness parameters, we propose a novel parameterization method for elastic impedance variation with offset and azimuth(EIVOA). By incorporating wide-azimuth observable seismic reflection data with regularization constraints, we utilize Bayesian seismic inversion to estimate the fluid content and fracture parameters of fractured porous rocks. Tests on synthetic and real data demonstrate that fluid and fracture properties can be reasonably estimated directly from azimuthal seismic data and the proposed approach provides a reliable method for fluid identification and fracture characterization in a gas-saturated fractured porous reservoir.     

Fluid identification based on P-wave anisotropy dispersion gradient inversion for fractured reservoirs

Fluid identification in fractured reservoirs is a challenging issue and has drawn increasing attentions. As aligned fractures in subsurface formations can induce anisotropy, we must choose parameters independent with azimuths to characterize fractures and fluid effects such as anisotropy parameters for fractured reservoirs. Anisotropy is often frequency dependent due to wave-induced fluid flow between pores and fractures. This property is conducive for identifying fluid type using azimuthal seismic data in fractured reservoirs. Through the numerical simulation based on Chapman model, we choose the P-wave anisotropy parameter dispersion gradient (PADG) as the new fluid factor. PADG is dependent both on average fracture radius and fluid type but independent on azimuths. When the aligned fractures in the reservoir are meter-scaled, gas-bearing layer could be accurately identified using PADG attribute. The reflection coefficient formula for horizontal transverse isotropy media by Rüger is reformulated and simplified according to frequency and the target function for inverting PADG based on frequency-dependent amplitude versus azimuth is derived. A spectral decomposition method combining Orthogonal Matching Pursuit and Wigner–Ville distribution is used to prepare the frequency-division data. Through application to synthetic data and real seismic data, the results suggest that the method is useful for gas identification in reservoirs with meter-scaled fractures using high-qualified seismic data.     

Azimuthal Seismic Amplitude Variation with Offset and Azimuth Inversion in Weakly Anisotropic Media with Orthorhombic Symmetry

Seismic amplitude variation with offset and azimuth (AVOaz) inversion is well known as a popular and pragmatic tool utilized to estimate fracture parameters. A single set of vertical fractures aligned along a preferred horizontal direction embedded in a horizontally layered medium can be considered as an effective long-wavelength orthorhombic medium. Estimation of Thomsen’s weak-anisotropy (WA) parameters and fracture weaknesses plays an important role in characterizing the orthorhombic anisotropy in a weakly anisotropic medium. Our goal is to demonstrate an orthorhombic anisotropic AVOaz inversion approach to describe the orthorhombic anisotropy utilizing the observable wide-azimuth seismic reflection data in a fractured reservoir with the assumption of orthorhombic symmetry. Combining Thomsen’s WA theory and linear-slip model, we first derive a perturbation in stiffness matrix of a weakly anisotropic medium with orthorhombic symmetry under the assumption of small WA parameters and fracture weaknesses. Using the perturbation matrix and scattering function, we then derive an expression for linearized PP-wave reflection coefficient in terms of P- and S-wave moduli, density, Thomsen’s WA parameters, and fracture weaknesses in such an orthorhombic medium, which avoids the complicated nonlinear relationship between the orthorhombic anisotropy and azimuthal seismic reflection data. Incorporating azimuthal seismic data and Bayesian inversion theory, the maximum a posteriori solutions of Thomsen’s WA parameters and fracture weaknesses in a weakly anisotropic medium with orthorhombic symmetry are reasonably estimated with the constraints of Cauchy a priori probability distribution and smooth initial models of model parameters to enhance the inversion resolution and the nonlinear iteratively reweighted least squares strategy. The synthetic examples containing a moderate noise demonstrate the feasibility of the derived orthorhombic anisotropic AVOaz inversion method, and the real data illustrate the inversion stabilities of orthorhombic anisotropy in a fractured reservoir.     

Non-hyperbolic moveout inversion of wide-azimuth P-wave data for orthorhombic media

The azimuthally varying non‐hyperbolic moveout of P‐waves in orthorhombic media can provide valuable information for characterization of fractured reservoirs and seismic processing. Here, we present a technique to invert long‐spread, wide‐azimuth P‐wave data for the orientation of the vertical symmetry planes and five key moveout parameters: the symmetry‐plane NMO velocities, V⁽¹⁾_nmo and V⁽²⁾_nmo , and the anellipticity parameters, η⁽¹⁾, η⁽²⁾ and η⁽³⁾ . The inversion algorithm is based on a coherence operator that computes the semblance for the full range of offsets and azimuths using a generalized version of the Alkhalifah–Tsvankin non‐hyperbolic moveout equation. The moveout equation provides a close approximation to the reflection traveltimes in layered anisotropic media with a uniform orientation of the vertical symmetry planes. Numerical tests on noise‐contaminated data for a single orthorhombic layer show that the best‐constrained parameters are the azimuth ? of one of the symmetry planes and the velocities V⁽¹⁾_nmo and V⁽²⁾_nmo , while the resolution in η⁽¹⁾ and η⁽²⁾ is somewhat compromised by the trade‐off between the quadratic and quartic moveout terms. The largest uncertainty is observed in the parameter η⁽³⁾ , which influences only long‐spread moveout in off‐symmetry directions. For stratified orthorhombic models with depth‐dependent symmetry‐plane azimuths, the moveout equation has to be modified by allowing the orientation of the effective NMO ellipse to differ from the principal azimuthal direction of the effective quartic moveout term. The algorithm was successfully tested on wide‐azimuth P‐wave reflections recorded at the Weyburn Field in Canada. Taking azimuthal anisotropy into account increased the semblance values for most long‐offset reflection events in the overburden, which indicates that fracturing is not limited to the reservoir level. The inverted symmetry‐plane directions are close to the azimuths of the off‐trend fracture sets determined from borehole data and shear‐wave splitting analysis. The effective moveout parameters estimated by our algorithm provide input for P‐wave time imaging and geometrical‐spreading correction in layered orthorhombic media.     

AVO investigations of shallow marine sediments

Amplitude‐variation‐with‐offset (AVO) analysis is based on the Zoeppritz equations, which enable the computation of reflection and transmission coefficients as a function of offset or angle of incidence. High‐frequency (up to 700 Hz) AVO studies, presented here, have been used to determine the physical properties of sediments in a shallow marine environment (20 m water depth). The properties that can be constrained are P‐ and S‐wave velocities, bulk density and acoustic attenuation. The use of higher frequencies requires special analysis including careful geometry and source and receiver directivity corrections. In the past, marine sediments have been modelled as elastic materials. However, viscoelastic models which include absorption are more realistic. At angles of incidence greater than 40°, AVO functions derived from viscoelastic models differ from those with purely elastic properties in the absence of a critical angle of incidence. The influence of S‐wave velocity on the reflection coefficient is small (especially for low S‐wave velocities encountered at the sea‐floor). Thus, it is difficult to extract the S‐wave parameter from AVO trends. On the other hand, P‐wave velocity and density show a considerably stronger effect. Attenuation (described by the quality factor Q) influences the reflection coefficient but could not be determined uniquely from the AVO functions. In order to measure the reflection coefficient in a seismogram, the amplitudes of the direct wave and the sea‐floor reflection in a common‐midpoint (CMP) gather are determined and corrected for spherical divergence as well as source and streamer directivity. At CMP locations showing the different AVO characteristics of a mud and a boulder clay, the sediment physical properties are determined by using a sequential‐quadratic‐programming (SQP) inversion technique. The inverted sediment physical properties for the mud are: P‐wave velocity α=1450±25 m/s, S‐wave velocity β=90±35 m/s, density ρ=1220±45 kg/m³, quality factor for P‐wave Q_P=15±200, quality factor for S‐wave Q_S=10±30. The inverted sediment physical properties for the boulder clay are: α=1620±45 m/s,β=360±200 m/s,ρ=1380±85 kg/m³,Q_P=790±660,Q_S=25±10.     

煤层气储层物性预测的AVO技术对地震纵波资料品质要求的探讨

煤层的含气性及渗透性可以利用纵波AVO技术及基于各向异性理论的方位AVO技术进行研究.煤层气属于吸附气,储层厚度较薄,地震异常响应较弱,对地震资料的品质及其携带的信息量提出了更高的要求.本文对AVO与方位AVO反演理论的近似条件及模型试算结果进行了分析,提出了对地震纵波数据信噪比、入射角、偏移距分布及方位角分布等参数的要求:1.观测系统设计及野外采集时应保证地震波的有效入射角在0.～30.或更大范围内,偏移距应大中小均匀分布,避免过于集中或缺失.2.地震数据应有足够宽分布的方位角,煤层气地震勘探中应选择宽方位观测系统.3、地震资料信噪比应足够高.     

Azimuthally pre-stack seismic inversion for orthorhombic anisotropy driven by rock physics

Based on the long-wavelength approximation, a set of parallel vertical fractures embedded in periodic thin interbeds can be regarded as an equivalent orthorhombic medium. Rock physics is the basis for constructing the relationship between fracture parameters and seismic response. Seismic scattering is an effective way to inverse anisotropic parameters. In this study, we propose a reliable method for predicting the Thomsen’s weak anisotropic parameters and fracture weaknesses in an orthorhombic fractured reservoir using azimuthal pre-stack seismic data. First, considering the influence of fluid substitution in mineral matrix, porosity, fractures and anisotropic rocks, we estimate the orthorhombic anisotropic stiffness coefficients by constructing an equivalent rock physics model for fractured rocks. Further, we predict the logging elastic parameters, Thomsen’s weak parameters, and fracture weaknesses to provide the initial model constraints for the seismic inversion. Then, we derive the P-wave reflection coefficient equation for the inversion of Thomsen’s weak anisotropic parameters and fracture weaknesses. Cauchy-sparse and smoothing-model constraint regularization taken into account in a Bayesian framework, we finally develop a method of amplitude variation with angles of incidence and azimuth (AVAZ) inversion for Thomsen’s weak anisotropic parameters and fracture weaknesses, and the model parameters are estimated by using the nonlinear iteratively reweighted least squares (IRLS) strategy. Both synthetic and real examples show that the method can directly estimate the orthorhombic characteristic parameters from the azimuthally pre-stack seismic data, which provides a reliable seismic inversion method for predicting Thomsen’s weak anisotropic parameters and fracture weaknesses.     

Seismic characterization of reservoirs with multiple fracture sets using velocity and attenuation anisotropy data

Knowledge about the spatial distribution of the fracture density and the azimuthal fracture orientation can greatly help in optimizing production from fractured reservoirs. Frequency-dependent seismic velocity and attenuation anisotropy data contain information about the fractures present in the reservoir. In this study, we use the measurements of velocity and attenuation anisotropy data corresponding to different seismic frequencies and azimuths to infer information about the multiple fracture sets present in the reservoir. We consider a reservoir model with two sets of vertical fractures characterized by unknown azimuthal fracture orientations and fracture densities. Frequency-dependent seismic velocity and attenuation anisotropy data is computed using the effective viscoelastic stiffness tensor and solving the Christoffel equation. A Bayesian inversion method is then applied to measurements of velocity and attenuation anisotropy data corresponding to different seismic frequencies and azimuth to estimate the azimuthal fracture orientations and the fracture densities, as well as their uncertainties. Our numerical examples suggest that velocity anisotropy data alone cannot recover the unknown fracture parameters. However, an improved estimation of the unknown fracture parameters can be obtained by joint inversion of velocity and attenuation anisotropy data.     

Moveout approximation for horizontal transversely isotropic and vertical transversely isotropic layered medium. Part I: 1D ray propagation‡

Anisotropy in subsurface geological models is primarily caused by two factors: sedimentation in shale/sand layers and fractures. The sedimentation factor is mainly modelled by vertical transverse isotropy (VTI), whereas the fractures are modelled by a horizontal transversely isotropic medium (HTI). In this paper we study hyperbolic and non‐hyperbolic normal reflection moveout for a package of HTI/VTI layers, considering arbitrary azimuthal orientation of the symmetry axis at each HTI layer. We consider a local 1D medium, whose properties change vertically, with flat interfaces between the layers. In this case, the horizontal slowness is preserved; thus, the azimuth of the phase velocity is the same for all layers of the package. In general, however, the azimuth of the ray velocity differs from the azimuth of the phase velocity. The ray azimuth depends on the layer properties and may be different for each layer. In this case, the use of the Dix equation requires projection of the moveout velocity of each layer on the phase plane. We derive an accurate equation for hyperbolic and high‐order terms of the normal moveout, relating the traveltime to the surface offset, or alternatively, to the subsurface reflection angle. We relate the azimuth of the surface offset to its magnitude (or to the reflection angle), considering short and long offsets. We compare the derived approximations with analytical ray tracing.     

利用全方位P波属性进行裂缝检测的地震方法

胜利油田存在着一种特殊的裂隙性油气藏,即泥岩裂隙油气藏。由于该类裂隙储层的孔隙度很小,岩石物性参数变化不灵敏,并表现出很强的各向异性,因此,其勘探难度很大。到目前为止,国内外还没有一套成熟的地质、物探、测井及钻井等资料综合分析的裂隙方位、分布、密度的识别方法。本文在研究国外裂缝检测方法的基础上,提出了波阻抗随方位变化(IPVA)的新方法,结合罗家地区的泥岩裂隙地震地质特征,研究了利用多方位 P 波资料检测定向垂直裂缝的地震采集、处理和识别方法,对不同共中心点 CMP 位置的全方位 P 波资料在速度随方位变化(VVA)及振幅随方位角变化(RVA)研究的基础上,进行波阻抗随方位变化(IPVA)的研究,用于识别裂缝的分布、走向及密度。经罗家地区实际资料的应用,见到了初步的效果,证明该方法是潜力较大的高角度裂隙的定量检测方法。     

利用叠前地震数据预测裂缝储层的应用研究

叠前地震资料储层预测技术是在Zoeppritz方程基础上发展起来的,通过处理地震数据随着不同入射角地震反射属性,得到地震属性随着入射角变化而改变,研究分析得到反映岩性变化的纵波速度、横波速度、泊松比和截距与梯度剖面,预测裂缝储层的发育及分布.同时根据不同方位角地震资料属性,计算得到不同方位角目的层的属性差异,使用各向异性椭圆公式作拟合,求出背景趋势A和各向异性因子B,利用最大振幅包络方位和对应θ,求出裂缝发育优势方向,及B/A各向异性因子,实现对裂缝储层预测.     

CONVERSION POINTS AND TRAVELTIMES OF CONVERTED WAVES IN PARALLEL DIPPING LAYERS1

For converted waves, stacking as well as AVO analysis requires a true common reflection point gather which, in this case, is also a common conversion point (CCP) gather. The coordinates of the conversion points for PS or SP waves, in a single homogeneous layer can be calculated exactly as a function of the offset, the reflector depth and the ratio v_p/v_s. An approximation of the conversion point on a dipping interface as well as for a stack of parallel dipping layers is given. Numerical tests show that the approximation can be used for offsets smaller than the depth of the reflector under consideration. The traveltime of converted waves in horizontal layers can be expanded into a power series. For small offsets a two-term truncation of the series yields a good approximation. This approximation can also be used in the case of dipping reflectors if a correction is applied to the traveltimes. This correction can be calculated from the approximated conversion point coordinates.