Collecting seismic data requires an energy source to generate waves and sensors to receive those waves. The appropriate energy source and receiver depend on the location and the application. This article describes different types of equipment used for seismic data acquisition. A variety of seismic sources exist that can apply vertical impulse forces to the surface of the ground. These devices are viable energy sources for onshore seismic work.
Assuming that the amplitudes are accurately rendered, a host of additional features can be derived and used in interpretation. Collectively, these features are referred to as seismic attributes. The simplest attribute, and the one most widely used, is seismic amplitude, and it is usually reported as the maximum (positive or negative) amplitude value at each sample along a horizon picked from a 3D volume. It is fortunate that, in many cases, the amplitude of reflection corresponds directly to the porosity or to the saturation of the underlying formation. Attributes can be obtained from typical post-stack seismic data volumes, and these are the most common types.
Interpreting seismic data requires an understanding of the subsurface formations and how they may affect wave reception. This article discusses some of the key stratal interfaces and their implications for interpreting the data received. All instantaneous seismic attributes (amplitude, phase, frequency) can be used in interpretation. In practice, most interpreters use instantaneous amplitude, or some variation of an amplitude attribute, as their primary diagnostic tool. Amplitude is related to reflectivity, which in turn is related to subsurface impedance contrasts.
A variety of seismic sources exist that can apply vertical impulse forces to the surface of the ground. These devices are viable energy sources for onshore seismic work. Included in this source category are gravity-driven weight droppers and other devices that use explosive gases or compressed air to drive a heavy pad vertically downward. Multiple references describe these types of sources. Chemical explosives are no longer used as marine energy sources for environmental and ecological reasons. First, it should be determined whether the selected impulsive source creates adequate energy input to provide data with an appropriate signal-to-noise ratio and a satisfactory signal bandwidth at appropriate offset distances. Second, it is important to determine whether an impulsive source causes unwanted reverberations in shallow strata. Vibroseis energy sources are some of the more popular seismic source options for onshore hydrocarbon exploration. Vibrators have several features that make them attractive for seismic data acquisition.
In some reservoir applications, seismic data are acquired with downhole sources and receivers. If the receiver is stationed at various depth levels in a well and the source remains on the surface, the measurement is called vertical seismic profiling (VSP). This image, a 2D profile restricted to the vertical plane passing through the source and receiver coordinates, is useful in tying seismic responses to subsurface geologic and engineering control. If the source is deployed at various depth levels in one well and the receiver is placed at several depth stations in a second well, the measurement is called crosswell seismic profiling (CSP). Images made from CSP data have the best spatial resolution of any seismic measurement used in reservoir characterization because a wide range of frequencies is recorded.
There are several specific differences between exploration geophysics and reservoir geophysics, as the term is usually intended. The differences include: the assumption that well control is available within the area of the geophysical survey; a carefully designed geophysical survey can be conducted at a level of detail that will be useful; some understanding of the rock physics is available for interpretation; 3D seismic (or other geophysical) data can be collected; and geostatistical techniques can be applied to it. The reservoir geophysicist should be familiar with the usefulness and limitations of petrophysical and reservoir-engineering studies and should be able to ask intelligent questions of the experts in those fields. However, the reservoir geophysicist typically is not an expert in those areas and works with the appropriate specialists to interpret the data or to design a new experiment to solve reservoir problems. In exploration, extrapolation of well data from far outside the area of interest is often necessary, and the interpretation is required to cross faults, sequence boundaries, pressure compartments, and other discontinuities that may or may not be recognized.
Drilling engineers require estimates of the fluid pressures that they are likely to encounter in any given well to anticipate mud weights required to maintain optimal drilling rates and safety. Because seismic velocities correlate with effective pressure in the formation, sufficiently precise estimates of velocity obtained from seismic observations can be used to determine pore pressure. In the absence of dense well control, interval velocities derived from stacking velocities are used to estimate pore pressure. These interval velocities are compared with a general trend of velocities in the region (Figure 1), and a pore pressure volume is developed for use by drilling engineers, as shown in Figure 1. Acoustic impedance volumes obtained from seismic trace inversion can also be used to identify and detect anomalous pore pressure regions.
Traditional methods of monitoring reservoir behavior, including reservoir simulation and history-matching with production rates and pressure, can produce nonunique solutions for reservoir behavior in the interwell regions. In some instances, the uncertainty can be significant, and additional information is needed to optimize production and improve estimates of ultimate recovery. In many cases, the effect of the changing reservoir pressure and/or saturation on seismic data can be used to map the changing pattern of these reservoir properties by obtaining seismic data repeatedly during production of the reservoir. With care, seismic data obtained for other purposes (such as regional exploration) can sometimes be used for time-lapse seismic monitoring, but new data are often obtained from seismic experiments designed particularly to monitor the reservoir. The desire to minimize differences in acquisition parameters between surveys has led, in some cases, to permanent installation of sensors in the oilfield.
The ability of seismic reflection technology to image subsurface targets is possible largely through the geometry of sources and receivers. A method similar to triangulation is used to place reflections in their correct locations with (more-or-less) correct amplitudes, which can then be interpreted. The amplitudes are indicative of relative changes in impedance, and the seismic volume can be processed to yield impedances between the reflecting boundaries. These traces were recorded at different offset distances, and the travel times for seismic waves traveling to and from a given reflecting horizon varies with that distance (Figure 1). If the overburden through which the seismic waves pass is of constant velocity, then the time-variation with distance is a simple application of Pythagorean geometry, and the shape of the reflector on a seismic "gather" of traces is hyperbolic.