Surface Seismic Experiments Research Articles

A feasibility study for detection thresholds of CO 2 at shallow depths at the CaMI Field Research Station, Newell County, Alberta, Canada

We present the results of a feasibility study for seismic monitoring using conventional surface seismic experiments at the CaMI Field Research Station, Alberta, Canada, where a small volume of gas-phase CO 2 is being injected into a sandstone reservoir at a depth of 300 m. We first apply a careful fluid substitution procedure to the results of reservoir gas saturation and pressure responses obtained from fluid flow simulations. We test different methods to compute the bulk modulus of the fluid for different fluid saturation models. Assuming a semi-patchy model and considering only the replacement of brine with a maximum saturation of 50% CO 2 , we estimate the reduction in P-wave velocity to be 20%. Adding an increase in pore pressure of 2.7 MPa increases the P-wave velocity reduction to 32%. After including a field-based signal-to-noise ratio of 5% to the synthetic seismic data, the time-lapse seismic anomaly should be detectable after one year of injection (266 tonnes of CO 2 ).

Analysis of the traveltime sensitivity kernels for an acoustic transversely isotropic medium with a vertical axis of symmetry

ABSTRACTIn anisotropic media, several parameters govern the propagation of the compressional waves. To correctly invert surface recorded seismic data in anisotropic media, a multi‐parameter inversion is required. However, a tradeoff between parameters exists because several models can explain the same dataset. To understand these tradeoffs, diffraction/reflection and transmission‐type sensitivity‐kernels analyses are carried out. Such analyses can help us to choose the appropriate parameterization for inversion. In tomography, the sensitivity kernels represent the effect of a parameter along the wave path between a source and a receiver. At a given illumination angle, similarities between sensitivity kernels highlight the tradeoff between the parameters. To discuss the parameterization choice in the context of finite‐frequency tomography, we compute the sensitivity kernels of the instantaneous traveltimes derived from the seismic data traces. We consider the transmission case with no encounter of an interface between a source and a receiver; with surface seismic data, this corresponds to a diving wave path. We also consider the diffraction/reflection case when the wave path is formed by two parts: one from the source to a sub‐surface point and the other from the sub‐surface point to the receiver. We illustrate the different parameter sensitivities for an acoustic transversely isotropic medium with a vertical axis of symmetry. The sensitivity kernels depend on the parameterization choice. By comparing different parameterizations, we explain why the parameterization with the normal moveout velocity, the anellipitic parameter η, and the δ parameter is attractive when we invert diving and reflected events recorded in an active surface seismic experiment.

Imaging by forward propagating the data: theory and application

ABSTRACTThe forward (modelled) wavefield for conventional reverse time migration (RTM) is computed by extrapolating the wavefield from an estimated source wavelet. In the typical case of a smooth subsurface velocity, this wavefield lacks the components, including surface reflections, necessary to image multiples in the observed data. We, instead, introduce the concept of forward propagating the recorded data, including direct arrivals, as part of RTM. We analyse the influence of the main components of the data on the imaging process, which include direct arrivals, primaries and surface‐related multiples. In our RTM methodology, this implies correlating the forward extrapolated recorded data wavefield with its reversely extrapolated version prior to applying the zero‐lag cross‐correlation imaging condition. The interaction of the data components with each other in the cross‐correlation process will image primaries and multiples, as well as introduce cross‐talk artefact terms. However, some of these artefacts are present in conventional RTM implementation and they tend to be relatively weak. In fact, for the surface seismic experiment, forward propagating the direct arrivals is almost equivalent to forward propagating a source and it tends to contribute the majority of the data imaging energy. In addition, primaries and multiples recorded in the data become multiples of one higher order. Forward propagating the recorded data to recreate the source will relieve us from the requirement of estimating the source function. It will also include near‐surface information necessary to improve the image in areas with near‐surface complexity. Data from a simple synthetic layered model, as well as the Marmousi model, are used to demonstrate some of these features.

Applications of deterministic and stochastic rock physics modelling to anisotropic velocity model building

ABSTRACTModern anisotropic depth imaging requires transverse isotropy velocity models. Because the surface seismic experiment alone cannot uniquely determine all transverse isotropy parameters, additional information is required. Traditional methods that use checkshots can only constrain anisotropy locally near the well and thus model building requires 3D extrapolation of well data. We propose to use rock physics. Rock physics compaction modelling of shales and sandy shales can be used to constrain and predict anisotropic parameters of sediments whose depositional environment is governed by compaction. In this study, we present several applications of rock physics modelling to anisotropic velocity model building. We show how both deterministic and stochastic rock physics modelling can be used for initial anisotropic velocity model building and as a constraint for anisotropic parameter estimation. In all cases, all predicted anisotropy models are physical and realizable in terms of effective medium theory and do not violate elasticity theory.

Green’s theorem as a comprehensive framework for data reconstruction, regularization, wavefield separation, seismic interferometry, and wavelet estimation: A tutorial

Almost every link in the chain of exploration seismology methods used to process recorded data has been affected by Green’s theorem. Among the seismic processes that can be related to, and/or have benefited from, Green’s theorem are wavelet estimation, multiple elimination, regularization, redatuming, imaging, deghosting, and interferometry. This tutorial on various seismic exploration methods derived from Green’s theorem emphasizes seismic data reconstruction (including regularization and redatuming) and its relationship to interferometry as well as to wavelet estimation and wavefield separation. The last decade has witnessed ever-increasing attention within the energy industry and its concomitant representation in the published literature to methods dealing with wavefield reconstruction through in-terferometry or virtual-source techniques. The attention has re- newed interest in Green’s theorem because all different ap-proaches to interferometry can be derived from it. This tutorial provides a derivation and explication of the limitations of interferometric techniques (when interferometry is used to process measured data from marine surface seismic experiments with controlled sources) as approximations to Green’s theorem. This tutorial provides a definite statement of the comprehensive framework given by Green’s theorem to wavefield reconstruction and shows how different techniques are directly understood as specific mathematical forms and/or approximations to the theorem. The use of approximations can have shortcomings and create artifacts. These artifacts and errors are also analyzed and explained. All methods discussed in this tutorial recognize their foundation on Green’s theorem and have a secure mathematical-physics cornerstone to recognize the assumptions behind distinct approximate solutions and to guide the search for more accurate, effective techniques.

Resolution analysis for stereotomography in media with elliptic and anelliptic anisotropy

Stereotomography is a tomographic method that uses slowness-vector components to improve traveltime inversion. We extend it to general anisotropic media and implement it for media with elliptic and anelliptic anisotropy. Such media depend on only three elastic parameters, which makes stereotomography less sensitive to ambiguity resulting from limited coverage of surface seismic experiments than it would be in transversely isotropic or orthorhombic media. The corresponding approximations of the slowness surface restrict the validity of the present approach to qP events and mild anisotropy. Our numerical analysis demonstrates that stereotomography can be used to estimate macrovelocity models in the presence of anisotropy. For elliptic anisotropy, the parameter that is most difficult to estimate is the orientation of the symmetry axis. For anelliptic anisotropy, estimation of stereotomography parameters is possible in principle; however, it will be mostly ill conditioned in practice, even for low noise levels. Better results are achieved, if transmission events from multiple-offset vertical seismic profiling experiments are included in the inversion.

Acquisition geometry requirements for generating virtual-source data

Using model and field data, this article reviews the virtual-source method and its acquisition geometry requirements. Before we go into the details of the acquisition geometry requirements, let us briefly review the basic concept and the advantages of the virtual-source method. A typical surface seismic experiment has sources on the surface to excite waves that propagate through the subsurface. Surface receivers record the reflected waves. In order to image the subsurface, we migrate the reflected wavefield recorded by the receivers, using an estimate of the subsurface velocity model. However, the near surface is usually complex, and the velocity is difficult to estimate. These near-surface inhomogeneities, if not represented in the migration velocity model, defocus the deeper image. In order to avoid the estimation of the near-surface velocity model, Bakulin and Calvert (2006) proposed the virtual-source method, a technique that uses cross-correlation of the wavefield recorded by a given pair of receiver...

Seismic Detection Limits of Small, Deep, Man-Made Reflectors: A Test at a Geothermal Site in Northern Germany

A key question for the development of geothermal plants is the seismic detection and monitoring of fluid injections at several kilometers depth. The detection and monitoring limits are controlled by several parameters, for example, the strength of seismic sources, number of receivers, vertical stacking, and noise conditions. For a known reference reflector at 2.66 km depth at a geothermal site in northern Germany the results of a simple surface seismic experiment were therefore combined with numerical forward modeling for different injection scenarios at 3.8 km depth. The underlying idea is that changes of reflectivity from the injection at 3.8 km must be larger than the variance of the measurements to be observable. Assuming that the injection at 3.8 km depth would produce a subhorizontal disklike target with a fracture porosity of 2% or 5% (the critical porosity) the water injection volume has to be at least 443 and 115 m 3 , respectively, to be detectable from the surface. If the injection on the other hand does not create subhorizontal but subvertical pathways or only reduces the seismic velocities via the increased pore pressure in the immediate vicinity of the bore hole, the injection is undetectable from the surface. The most promising approach is therefore to move sources and/or receivers closer to the target, that is, the use of borehole instrumentation.

Preliminary results from investigations of seismic and petrophysical properties of Faroes basalts in the SeiFaBa project

The development of methods of seismic imaging beneath basalts is still hindered by a lack of knowledge about the elastic properties of basaltic sequences and the degree of three-dimensional heterogeneity. The SeiFaBa project (2002–2005) is funded by the Sindri Group as part of the programmes for licensees within the Faroese area and will attempt to address these issues. The Glyvursnes-1 well was drilled by SeiFaBa through the Upper Basalt Formation outside Tórshavn in 2002. A full core and numerous wireline logs were acquired from the 700m deep well. During the same operations, the existing 660m deep Vestmanna-1 well drilled mainly into the Middle Basalt Formation was reamed and logged. The two wells are central to a number of closely co-ordinated experiments, which are all targeted at creating models for seismic wave propagation through a succession of basalt by combining detailed analysis at core, log and seismic scales. Data from these two wells, in combination with the data for the Lopra-1 well drilled into the Lower Basalt Formation, will give new stratigraphic and petrophysical control of the Lower, Middle and Upper Basalt formations on the Faroes. The seismic programme was initiated in 2002 and the main acquisition was carried out during 2003. The well site at Glyvursnes gives optimal conditions for combining VSP, offset-VSP and surface seismic experiments both onshore and offshore and the seismic effects of a nearby near-vertical shear zone can be studied in detail. Preliminary analysis of log data from the Lopra-1 well suggests that the acoustic properties of these basalt flows are mainly controlled by porosity of a stiff matrix filled with clay minerals and water. Further studies will allow for explanations of the sonic response of basalt in terms of physical and compositional properties and a better understanding of the seismic signatures of flood basalt successions.

On anelliptic approximations for qP velocities in VTI media

ABSTRACTA unified approach to approximating phase and group velocities of qP seismic waves in a transversely isotropic medium with vertical axis of symmetry (VTI) is developed. While the exact phase‐velocity expressions involve four independent parameters to characterize the elastic medium, the proposed approximate expressions use only three parameters. This makes them more convenient for use in surface seismic experiments, where the estimation of all four parameters is problematic. The three‐parameter phase‐velocity approximation coincides with the previously published ‘acoustic’ approximation of Alkhalifah. The group‐velocity approximation is new and noticeably more accurate than some of the previously published approximations. An application of the group‐velocity approximation for finite‐difference computation of traveltimes is shown.

Calibrating well logs to VSP attributes: interval velocity and amplitude

The vertical seismic profile (VSP) occupies a unique niche in the discipline of reservoir characterization. It provides a level of resolution and a volume of investigation in between those offered by surface seismic data and well logging tools. The relationship between VSP and surface seismic experiments is obvious: The most common use of VSP is in high-resolution reflection imaging and tying surface seismic sections to depth. The relationship between VSP and acoustic well logging is less well explored. Interval velocities from check shot VSP are often used as coarse equivalents of sonic logs, but significant discrepancies are often seen. There are several reasons why we should not expect VSP interval velocities and sonic logs to match perfectly. Many of these reasons are discussed in Stewart et al. (1984) and include the volume of rock sampled by each method, instrumental biases, and wave propagation effects such as anisotropy, short-path multiples, and velocity dispersion. Because there is some interesting physics behind some of these potential discrepancies, several people have proposed using the differences between sonic log and VSP velocities to extract information about the formation. Because of the larger volume of investigation, most of which may be considered to be undisturbed by the presence of the borehole, VSP is often considered to be more reflective of the true formation properties. Thus, the calibration of sonic logs to VSP is also of importance. Another use of VSP which is gaining in popularity is the direct extraction of attenuation information, or Q values. This typically involves comparing downgoing wave amplitudes at successive receiver locations (often in the frequency domain), and computing a Q value for the interval. Unfortunately, scattering and other elastic effects often dominate the amplitude fluctuations, frequently resulting in nonphysical negative Q values. Recently, there has been progress in using elastic models …

Subsurface imaging using reversed vertical seismic profiling and crosshole tomographic methods

A combined reversed vertical seismic profile (RVSP), crosshole, and surface seismic experiment was performed to image the subsurface between two 1000 ft wells separated by 600 ft. Explosives were used as downhole sources and a 24-channel hydrophone streamer provided the downhole receivers. Surface shots were 1/3 lb dynamite charges and the surface receivers were vertical geophones. RVSP data, consisting of 48 offsets ranging from 25 ft to 1200 ft, were processed with a ray‐tracing method to produce an equivalent stacked seismic section. The crosshole data were processed with an SIRT traveltime transmission tomography algorithm to produce a velocity cross‐section. The stacked RVSP subsurface image and the crosshole tomography velocity cross‐section both have higher resolution than does the surface seismic image. For example, the velocity map from tomography exhibits a rapid lateral velocity change that is not resolved by surface seismic. However, all three methods agree within the limits of their common resolution. The results indicate that RVSP and crosshole tomography can potentially be used to image steeply dipping beds or complex structures, such as small faults, pinchouts, steam‐flooded zones, reef boundaries, or the flanks of salt domes.