Wells and logs: the other source of truth

Prerequisites

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 $\Delta t = 1/V_p$ 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. Dense rock scatters fewer gammas back; 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 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. A boundary where GR spikes up, DT jumps up, and RHOB drops a bit is classic shale entering from below. A clean sand shows low GR, low DT, and a density that depends on porosity and fluid.

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:

Z(z) = \rho(z) \cdot V_p(z)

Take the difference across consecutive samples and you have the reflectivity series. Convolve reflectivity 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.