Wells and logs: the other source of truth
Learning objectives
- Explain what a well log measures and why logs anchor seismic interpretation
- Identify the four most important logs for seismic work: gamma ray, sonic, density, and neutron porosity
- Read a composite log display and identify lithology changes
- Understand how sonic and density logs together build the seismic reflectivity we will see in Part 1
Seismic data is the only way to image the subsurface over large areas, but it has a built-in tradeoff: you get wide coverage, but your vertical resolution is tens of metres and your measurements are indirect. Wells give you the complement: a narrow, deep window through the rock where sensors record the properties of the formation metre by metre. An interpreter who ignores well data is guessing; an interpreter who blends well and seismic is doing science.
What a well is, and how a log is made
A well is a borehole drilled into the earth, typically 15-30 cm wide, that can extend to several kilometres depth. After drilling, a logging tool, an instrumented cylinder dangling on a cable, is lowered down the hole. As it is winched back up, sensors on the tool record the rock’s properties at roughly 15 cm depth intervals. Different tools measure different things; the record each tool produces is called a log.
Of the dozen-plus log types, four matter most for seismic interpretation.
The gamma-ray (GR) log
Measures natural gamma radiation from the formation. Clay minerals contain more radioactive elements (thorium, uranium, potassium) than clean sands or carbonates, so gamma-ray roughly tracks clay content. High GR values ⇒ shale; low GR values ⇒ clean sand or carbonate. It is the go-to log for a quick lithology-by-depth read.
Typical units: API (a calibration unit). Shales often read 80-150 API; clean sandstones 10-60 API; carbonates variable but often lower than shales.
The sonic (DT) log
Measures the time it takes an acoustic pulse to travel from a transmitter to a receiver across a fixed distance in the borehole. Units: microseconds per foot (μs/ft) or microseconds per metre. Since in appropriate units, sonic directly gives you the P-wave velocity of the formation.
Interpretation shortcut: faster rock = smaller DT. A DT of 55 μs/ft corresponds to about 5500 m/s (tight limestone). A DT of 130 μs/ft corresponds to about 2350 m/s (soft shale or porous gas sand).
The density (RHOB) log
Measures the bulk density of the formation, typically by emitting gamma rays from a radioactive source and counting how many come back. Denser rock holds more electrons, which scatter and absorb the gammas on their way to the detector, so fewer arrive; the count rate is inverted to give ρ in g/cm³.
Typical ranges: shale 2.2-2.7, sandstone 2.0-2.7 (depending on porosity), carbonate 2.3-2.85, salt 2.0-2.1. Fluid in the pores matters: a gas sand can drop to 2.0 or below.
The neutron-porosity (NPHI) log
Emits neutrons and counts how many return. Hydrogen atoms (in water and hydrocarbons) slow down neutrons most effectively, so high neutron count returns ⇒ low hydrogen ⇒ low porosity. Reported as a porosity value directly (0 to ~0.45 for unconsolidated shales).
Combined with density, neutron gives you two independent reads on porosity. The cross-plot of density vs. neutron-porosity is one of the most-used diagnostic displays in petrophysics; gas sands jump away from the water line in a characteristic pattern.
When you display these logs side-by-side on the same depth track (a composite log), the story of the formation becomes visually obvious. Reading down the well, a step where GR rises sharply is the top of a shale; how DT and RHOB change there depends on how porous and how compacted the rock above it is. A clean sand shows low GR, with a DT and a density set by its porosity and its fluid. In the figure below you read one such well bed by bed, and follow the two logs that matter, sonic and density, down to the seismic trace they predict.
Three beds are worth stopping on. The gas leg of the sand, 1110 to 1150 m, has the low gamma ray of any clean sand, but its sonic slows to 112 μs/ft and its density falls to 2.02 g/cm³, and the neutron crosses to the right of the density: that is the crossover. Its impedance, 5.50 km/s·g/cm³, is 21 % below the shale above, so its top is a trough with , and the gas-water contact at 1150 m, a boundary inside one sand, is a peak of . Swap the gas for brine and the contact disappears (), while the top weakens to : the brine sand’s impedance, 6.74 km/s·g/cm³, sits so close to the shale’s 6.97 that its top barely reflects. The coal at 1290 m is not a reservoir at all, yet at its top is the strongest trough in the well, because coal is both light (1.45 g/cm³) and slow. A bright event marks a large impedance contrast, not necessarily a reservoir. And the synthetic in (f) shows the price of the wavelet: at 25 Hz a quarter wavelength in the coal is 24 m, longer than the 15 m coal, so its top and base are not resolved; the 40 m gas leg is resolved only above about 17 Hz.
How logs bridge to seismic
Here is the connection that makes well logs indispensable for seismic work. The two logs we need to compute seismic reflectivity are:
- The sonic log → P-wave velocity at every depth
- The density log → bulk density at every depth
Multiply them together and you get the acoustic impedance log:
Take the normalised step in impedance at each boundary, , and you have the reflectivity series. Place each step in two-way time by integrating the sonic, convolve with a seismic wavelet, and you have a synthetic seismogram, a prediction of what a seismic trace at the well location should look like. Matching that synthetic to the real seismic trace at the well is the well-to-seismic tie, the fundamental calibration step of interpretation. We will build one explicitly in Part 8, but the logs you just learned to read are the raw material.
References
- Bacon, M., Simm, R., & Redshaw, T. (2003). 3-D Seismic Interpretation. Cambridge University Press.
- Mavko, G., Mukerji, T., & Dvorkin, J. (2009). The Rock Physics Handbook (2nd ed.). Cambridge University Press.
- Sheriff, R. E., & Geldart, L. P. (1995). Exploration Seismology (2nd ed.). Cambridge University Press.
- Brown, A. R. (2011). Interpretation of Three-Dimensional Seismic Data (7th ed.). AAPG Memoir 42 / SEG IG13.