[Note: A version of this blog entry will appear in World Oil (March, 2010)]
From a geoscience point of view, there are two worlds in hydrocarbon exploration. First is the depth realm of geology as revealed by drilling and wireline logs. Second is the reflection time world of geology as seen by seismic data. The connection between time and depth is, predictably, a time-depth curve derived from sonic log or vertical seismic profile (VSP).
The sonic device is a long metal cylinder lowered into the well on wireline like any other logging tool. Once in place at some depth in the well, it is slowly pulled up. As the tool crawls up the well, it is generating data by emitting at one end high-frequency pulses and listening for pulse arrivals at the other end. The operating frequency for most sonic logs is ten to fifteen thousand Hertz, far beyond the 10-100 Hz range of surface seismic data. When the source acts, sound waves move through the drilling fluid and interact with rock along the well bore wall that typically has a much greater sound speed. This sets up a thing called a head wave that runs along the bore hole wall, as opposed to a reflection that would only travel in the fluid and bounce off the wall. Anyway, since the exact distance between the source and receiver is known, along with the fluid sound speed and hole diameter, the wave speed in the rock formation can be found. The sonic log actually outputs the delay time divided by the source-receiver distance in units of microseconds per foot, and the formation velocity in ft/s can be found using (1 000 000)/sonic. The quantity measured by the sonic log is termed the interval velocity because it represents the local formation P-wave speed averaged along a short interval of the well bore equal to the source-receiver spacing of 1-2 m. A digital sonic log yields an interval velocity reading every 0.3 m (0.5 ft) in depth.
The process of converting a sonic log to a time-depth curve involves integration. In effect the sonic log is a model of the earth consisting of thin layers. Each layer is the same thickness (0.3 m) and we know the velocity, so the vertical two-way travel time through each layer can be calculated. Starting from the top, we sum up these layer times to find the reflection time to all depths in the well. The result is a time-depth curve, but one with many potential sources of error.
First, a sonic log never reaches the earth surface. Tool specifications require the bore hole diameter to be less than about 50 cm (20 in), meaning that onshore sonic logs in petroleum exploration and production wells rarely get within 100 m of the surface. In seismic terms, this is the weathered zone and likely to contain unpredictable low-velocity rock. The sonic contains no information about this interval, so it is necessary to somehow figure out the reflection time from ground surface to the top of the sonic log and add this to the time-depth curve.
Sonic logs are sensitive to washouts and other hole problems, and it is not easy to get accurate sonic velocity in slow formations (velocity less then sound speed in mud). We also have the problem of frequency mismatch between sonic and 3D surface seismic data. Note only is the sonic seeing a tiny volume of rock compared surface seismic waves, it is also well-established that seismic velocity in fluid saturated porous rock varies with frequency. This leads to the notoriously difficult upscaling problem that involves modifying observed sonic readings to better match the long wavelength velocities seen by surface seismic data. Not many people agree on how to do this.
To address the missing near surface and other time-depth problems, a check shot survey can be run in conjunction with sonic logging. In a check shot survey receivers are located sparsely down the well, usually at casing points and key geologic boundaries. The measured quantity is just the first arrival time.
Compare all of this to a vertical seismic profile recorded using a source at the surface and many receiver locations down the well. The receivers record full traces for interpretation and receiver spacing is determined by spatial aliasing considerations, usually something like 3 m (10 ft). This gives actual traveltimes from the surface to points in the earth. The VSP considered here is often called a zero offset VSP, meaning that only a single source position is used and that it is as close to the wellhead as possible. There are also multioffset and multiazimuth VSPs which use many source locations. These are much more expensive and sometimes useful for local, high resolution imaging. However, a zero offset VSP is sufficient for event identification and other standard uses.
A zero offset VSP is the best and most direct method of associating a 3D seismic event with a geologic horizon since it has about the same frequency range (20-200 Hz) as surface data, the wavefield actually passes through the same near surface, and it is not sensitive to hole problems. And there are many important side-benefits. In standard 3D shooting we use various acquisition techniques to isolate P waves, but the earth is actually elastic and all types of shear and mode-converted waves are bouncing around down there confusing our interpretation. The VSP is unique in its ability to distinguish upgoing from downgoing waves, S from P and mode-converted waves, and primary reflections from multiples. The last point is critically important. The entire machinery of seismic imaging is based on primary events that have reflected only one time. Over the last half-century an arsenal methods have been developed to detect and remove multiples in surface seismic data. Even so, our abilities are limited by the nature of the data. VSP data is fundamentally different and allows direct observation of these multiples (and non-P waves).
You don't need a hundred VSPs in a project area, but you are at a competitive disadvantage without at least one.