Asymmetry in the time-lapse seismic response to injection and depletion

Large changes in seismic reflection amplitude have been observed around injectors, and result from the decrease in elastic‐wave velocity due to the increase in pore pressure in the reservoir. In contrast, the velocity change resulting from the decrease in pore pressure in depleting reservoirs is observed to be smaller in magnitude. Elastic‐wave velocities in sandstones vary with stress due to the presence of stress‐sensitive grain boundaries within the rock. Grain‐boundary stiffness increases non‐linearly with increasing compressive stress, due to increased contact between opposing faces of the boundary. This results in a change in velocity due to a decrease in pore pressure that is smaller than the change in velocity caused by an increase in pore pressure, in agreement with time‐lapse seismic observations. The decrease in porosity resulting from depletion is not fully recovered upon re‐pressurization, and this leads to an additional steepening of the velocity vs. effective stress curve for injection relative to depletion. This difference is enhanced by any breakage of cement or weakening of grain contacts that may occur during depletion and by the reopening or formation of fractures or joints and dilation of grain boundaries that may occur during injection.     

Seismic anisotropy of shales

Shales are a major component of sedimentary basins, and they play a decisive role in fluid flow and seismic‐wave propagation because of their low permeability and anisotropic microstructure. Shale anisotropy needs to be quantified to obtain reliable information on reservoir fluid, lithology and pore pressure from seismic data, and to understand time‐to‐depth conversion errors and non‐hyperbolic moveout. A single anisotropy parameter, Thomsen's δ parameter, is sufficient to explain the difference between the small‐offset normal‐moveout velocity and vertical velocity, and to interpret the small‐offset AVO response. The sign of this parameter is poorly understood, with both positive and negative values having been reported in the literature. δ is sensitive to the compliance of the contact regions between clay particles and to the degree of disorder in the orientation of clay particles. If the ratio of the normal to shear compliance of the contact regions exceeds a critical value, the presence of these regions acts to increase δ, and a change in the sign of δ, from the negative values characteristic of clay minerals to the positive values commonly reported for shales, may occur. Misalignment of the clay particles can also lead to a positive value of δ. For transverse isotropy, the elastic anisotropy parameters can be written in terms of the coefficients W₂₀₀ and W₄₀₀ in an expansion of the clay‐particle orientation distribution function in generalized Legendre functions. For a given value of W₂₀₀, decreasing W₄₀₀ leads to an increase in δ, while for fixed W₄₀₀, δ increases with increasing W₂₀₀. Perfect alignment of clay particles with normals along the symmetry axis corresponds to the maximum values of W₂₀₀ and W₄₀₀, given by and . A comparison of the predictions of the theory with laboratory measurements shows that most shales lie in a region of the (W₂₀₀, W₄₀₀)‐plane defined by W₄₀₀/W₂₀₀≤W^max₄₀₀/W^max₂₀₀ .     

Sensitivity of the elastic anisotropy and seismic reflection amplitude of the Eagle Ford Shale to the presence of kerogen

The Eagle Ford Shale of Central and South Texas is currently of great interest for oil and gas exploration and production. Laboratory studies show that the Eagle Ford Shale is anisotropic, with a correlation between anisotropy and total organic carbon. Organic materials are usually more compliant than other minerals present in organic‐rich shales, and their shapes and distribution are usually anisotropic. This makes organic materials an important source of anisotropy in organic‐rich shales. Neglecting shale anisotropy may lead to incorrect estimates of rock and fluid properties derived from inversion of amplitude versus offset seismic data. Organic materials have a significant effect on the PP and PS reflection amplitudes from the Austin Chalk/Upper Eagle Ford interface, the Upper Eagle Ford/Lower Eagle Ford interface, and the Lower Eagle Ford/Buda Limestone interface. The higher kerogen content of the Lower Eagle Ford compared with that of the Upper Eagle Ford leads to a negative PP reflection amplitude that dims with offset, whereas the PS reflection coefficient increases in magnitude with increasing offset. The PP and PS reflection coefficients at the Austin Chalk/Upper Eagle Ford interface, the Upper Eagle Ford/Lower Eagle Ford interface, and the Lower Eagle Ford/Buda Limestone interface all increase in magnitude with increasing volume fraction of kerogen.     

Azimuthal variation in AVO response for fractured gas sands

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

Stress‐dependent elastic anisotropy of sandstones

Elastic wave velocities in sandstones vary with stress due to the presence of discontinuities such as grain boundaries and microcracks within the rock. In the presence of non-hydrostatic stress fields the elastic wave velocities in sandstones often show significant stress-induced anisotropy. The elastic anisotropy due to any discontinuities within the rock can be written in terms of a second-rank and a fourth-rank tensor which quantify the effect on the elastic wave velocities of the orientation distribution and normal and shear compliances of the discontinuities. This allows elastic wave velocity measurements to be inverted to obtain the components of these tensors. Application of the method to ultrasonic velocity measurements made in a triaxial loading frame shows that a simple theory using only the second-rank tensor allows the P-wave stress-induced anisotropy to be predicted to reasonable accuracy from the S-wave anisotropy and vice versa, thus confirming the correctness of the underlying model. Deviations between the measurements and the predictions of this simplified theory are used to determine the ratio of the normal to shear compliance of the discontinuities. The discontinuities are found to be more compliant in shear than in compression.     

Fluid‐dependent shear‐wave splitting in fractured media

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. A shear wave propagating in an azimuthally anisotropic medium splits into two components with different polarizations if the source polarization is not aligned with the principal axes of the medium. For vertical propagation of shear waves in a horizontally layered medium containing vertical fractures, the shear‐wave splitting depends on the shear compliance of the fractures, but is independent of their normal compliance. If the fractures are not perfectly vertical, the shear‐wave splitting also depends on the normal compliance of the fractures. The normal compliance of a fluid‐filled fracture decreases with increasing fluid bulk modulus. For dipping fractures, this results in a decrease in shear‐wave splitting and an increase in shear‐wave velocity with increasing fluid bulk modulus. The sensitivity of the shear‐wave splitting to fluid bulk modulus depends on the interconnectivity of the fracture network, the permeability of the background medium and on whether the fracture is fully or partially saturated.     

Cretaceous continental margin evolution revealed using quantitative seismic geomorphology,offshore northwest Africa

The application of high‐resolution seismic geomorphology, integrated with lithological data from the continental margin offshore The Gambia, northwest Africa, documents a complex tectono‐stratigraphic history through the Cretaceous. This reveals the spatial‐temporal evolution of submarine canyons by quantifying the related basin depositional elements and providing an estimate of intra‐ versus extra‐basinal sediment budget. The margin developed from the Jurassic to Aptian as a carbonate escarpment. Followed by, an Albian‐aged wave‐dominated delta system that prograded to the palaeo‐shelf edge. This is the first major delivery of siliciclastic sediment into the basin during the evolution of the continental margin, with increased sediment input linked to exhumation events of the hinterland. Subaqueous channel systems (up to 320 m wide) meandered through the pro‐delta region reaching the palaeo‐shelf edge, where it is postulated they initiated early submarine canyonisation of the margin. The canyonisation was long‐lived (ca. 28 Myr) dissecting the inherited seascape topography. Thirteen submarine canyons can be mapped, associated with a Late Cretaceous‐aged regional composite unconformity (RCU), classified as shelf incised or slope confined. Major knickpoints within the canyons and the sharp inflection point along the margin are controlled by the lithological contrast between carbonate and siliciclastic subcrop lithologies. Analysis of the base‐of‐slope deposits at the terminus of the canyons identifies two end‐member lobe styles, debris‐rich and debris‐poor, reflecting the amount of carbonate detritus eroded and redeposited from the escarpment margin (blocks up to ca. 1 km³). The vast majority of canyon‐derived sediment (97%) in the base‐of‐slope is interpreted as locally derived intra‐basinal material. The average volume of sediment bypassed through shelf‐incised canyons is an order of magnitude higher than the slope‐confined systems. These results document a complex mixed‐margin evolution, with seascape evolution, sedimentation style and volume controlled by shelf‐margin collapse, far‐field tectonic activity and the effects of hinterland rejuvenation of the siliciclastic source.     

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.