Ultrasonic compressional and shear‐wave velocities of isotropic sands are shown to be dependent on their mineralogy, their porosity, their fluid content, and their state of consolidation, under fixed temperature and pressure conditions. This leads to a distinction between two broad classes of sands: those that are well consolidated, and those that are loosely consolidated. Changes in elastic velocities reflect changes in the ratio of bulk and shear moduli to density in response to lithologic variations. We decouple the two effects by examining changes in elastic moduli with respect to changes in lithology, and we observe three main points: (1) For consolidated sandstones, the effects of mineralogy and porosity can be approximated both empirically and theoretically by a modified isostrain theory: the dry bulk and shear moduli of the rock aggregate follow a “mixing law,” being linear combinations of the respective moduli of the individual constituents. The dry elastic moduli of families of clean sands and shaley sands are linear functions of porosity, with decreasing y‐axis intercepts as their clay‐to‐sand ratio increases. (2) Loosely consolidated sands and sandy shales appear to follow a behavior closer to that of the isostress theory for suspensions: the reciprocals of the bulk and shear moduli of the rock aggregate are linear combinations of the reciprocal moduli of their individual constituents. In general, the elastic moduli of poorly lithified sands are less sensitive to changes in mineralogy and porosity than those of consolidated sandstones. (3) For high permeability sands like the loosely consolidated sands of Troll, the Biot‐Gassman theory is a good approximation to the effects of fluids on seismic velocities. With our understanding of elastic moduli, we then show that dry ratios [Formula: see text] increase with porosity and clay content.

No abstract

Subsurface mocfels of Iithology are often poorly constrained due to the lack of dense well control. AIthough limited in vertical resohrtion, high quality 3-D seismic data usually provide vahtable information regsrdmg the lateral variations of Iithology. The Bayesian Sequential Indicator Simulation (BSISIM) technique is a new stochastic method to generate seismically constrained models of Iithology. Unlike cokriging-based simulation methods, BSISM does not-rely on a generalized linear regression rriodel, which is inadequate when combining fithology indicator variables and continuous seismic attributes. Instead, BSLSIIvluses a Bayesian updating rule to construct a posterior probability distribution of lithoclasses at each location. The posterior dkr-ibution combines a local prior distribution obtained by~dicator kriging wftb a function representing the ieismic likelihood of the different Iithofaties. The local posterior dk,tributions are sampled sequentially at all points irr space to generate realizations from the joint posterior dktribution. The realizations define alternative, gquiprobabIe Iithologic models, representing a comprortiise between fidelity to the seismic data, as measured by the likelihood functions, and consistency with spatial continuity information, as expressed by the lithology indicator correlation functions. The simulation technique References and figures at end of paper.is aodied to uredict the lateral distribution of channel ssn& in the N'ms Formation of the Oseberg Field. Channel sand maps are simulated using Lithologic observations in fourteen weIls, and seismic amplitude and channel orientation data extracted from a 3-D survey. Sand probability maps, generated by summarizing a large number of simulations, aIlow de~meation of the probable lateral extent of the channel deposits. Comparison of seismically derived lithologic models to well-derived models demonstrates the improved definition of channel geometry achieved by integrating the geophysical information.

No abstract

We perform a feasibility study on the likelihood of seismically detecting and interpreting the time-varying changes in a North Sea reservoir during solution-gas-drive oil production from a horizontal well. This study integrates reservoir engineering fluid-flow simulations, rock physics measurements and transformations, and prestack seismic modeling and migration on a real but anonymous North Sea reservoir model. We calculate spatial distributions of reservoir rock properties from the fluid-flow simulation data, and map the associated seismic responses at three production-time snapshots: prior to any oil production (Base Survey), after 56 days (Monitor 1), and after 113 days (Monitor 2) of oil production. Multi-offset seismic surveys are simulated for each of these three production times. Using realistic seismic acquisition parameters, we are able to successfully detect and monitor dynamic gascap expansion in the reservoir during the fluid-flow simulation of the oil production process. Evidence of gas coning is clearly visible in the prestackmigrated difference sections at realistic seismic noise levels and frequency bandwidth.