3
Formation Evaluation Module 3 · Petroleum Engineering
Module 3 · v1
Module 3 · Month 3 of 6

Formation Evaluation & Petrophysics

The bit has been through the rock. Now: what is it, how much oil does it hold, and will it flow? Petrophysics turns squiggly logs into the three numbers that decide a well — porosity, saturation, and pay — and it is the skill that separates a geologist's hunch from an engineer's reserves estimate.

Chapter 00·~5 min

How to read this #

Formation evaluation is the bridge from "we drilled it" to "here is what we have." Module 1 predicted the rock; Module 2 drilled it; now we measure it directly with tools lowered into the hole, and with rock brought to surface. The output feeds everything downstream: the reserves in Module 4, the completion design in Module 5.

The module builds toward one workflow. First, the measurements while drilling — mud logging — and the physics of logging tools and the borehole environment. Then the core log suite (the triple combo) and how each curve reads lithology, porosity, or fluid. Then the centerpiece: Archie's equation, which turns resistivity into water saturation, the number that says how much of the pore space is oil. Then the advanced tools, pressure and core data that pin the answer down, and finally the unconventional twist — finding and grading the landing zone for a lateral.

The three numbers

Strip everything down and petrophysics delivers three things per foot of hole: porosity (φ) — how much it holds; water saturation (Sw) — so 1−Sw is the oil/gas fraction; and net pay — which feet are good enough to count. Volumetrics (Module 1's STOIIP equation) is just these three integrated over the reservoir.

Chapter 01·Reading the hole

Mud logging #

The cheapest and earliest formation evaluation happens at the rig while drilling, in the mud-logging unit. It watches three streams in real time and is the first warning of both pay and trouble.

  • Cuttings — rock chips returned in the mud, washed and examined under a microscope for lithology, and tested for oil shows (fluorescence under UV, a "cut" when solvent is added).
  • Gas — a gas detector on the return flow measures total and chromatographic gas (C1–C5); ratios hint at oil vs gas and at pay zones.
  • Drilling parameters — ROP, weight on bit, torque. A drilling break (sudden ROP increase) can mean a porous, possibly pressured zone — a safety flag as much as a pay flag.
The mud logging data streams Mud returning from the well passes a gas detector and shaker where cuttings are caught; three tracks versus depth show rate of penetration, total gas, and a cuttings lithology column, with a drilling break and gas peak aligned at a pay zone. ROP total gas cuttings drilling break sand shale depth↓
Three aligned streams. A drilling break, a gas peak, and a clean-sand cuttings interval all at the same depth is the classic first sign of a pay zone — confirmed later by wireline logs.
Chapter 02·Reading the hole

Logging fundamentals #

A well log is a continuous record of a rock property versus depth, made by a tool in the borehole. Two ways to run them: wireline (tool lowered on a cable after drilling — high quality, but the hole must be stable) and LWD (sensors in the BHA measuring while drilling — essential in laterals where wireline can't easily go, and the eyes of geosteering).

The borehole environment: invasion

You are never measuring pristine rock. Drilling mud, held at higher pressure than the formation, pushes its filtrate into permeable rock near the wellbore, displacing the original fluids. This invasion creates a flushed zone (mud filtrate, resistivity Rxo) grading out to the undisturbed zone (true formation, Rt). Tools are designed with different depths of investigation precisely to see through invasion — shallow, medium, and deep resistivity curves whose separation reveals invasion and permeability.

The invasion profile A plan view of the borehole surrounded by concentric zones: the flushed zone with mud filtrate near the wall, a transition zone, and the undisturbed virgin formation, with shallow, medium, and deep resistivity tools reading progressively outward. flushed transition virgin (Rt) deep R → Rt (true) medium R shallow R → Rxo (flushed)
Mud filtrate invades permeable rock, so resistivity tools read different values at different depths. The separation between shallow and deep curves is itself information: it confirms permeability and helps correct to the true Rt that Archie needs.
Chapter 03·Reading the hole

The triple combo #

The standard first log suite — the triple combo — is three measurements that together give lithology, porosity, and saturation. It is the bread and butter of the discipline; learn to read it and you can evaluate most wells.

  • Gamma ray (GR) — natural radioactivity, high in shale (potassium, thorium, uranium in clays), low in clean sand/carbonate. The shale indicator and the depth-matching reference.
  • Resistivity — how the rock resists electric current. Brine conducts; hydrocarbons don't. High resistivity in a porous zone flags hydrocarbons. The input to Archie.
  • Porosity (density + neutron) — two tools that together give porosity and, by their relationship, fluid and lithology clues.
Reading a triple-combo log Three log tracks versus depth: gamma ray with shale baseline and a clean sand kick, deep and shallow resistivity separating and reading high in a pay zone, and density-neutron porosity curves crossing over in the same interval, with the pay zone highlighted across all tracks. Gamma ray Resistivity Density–Neutron PAY shale sand high crossover depth↓
The classic pay signature read across all three tracks at once: GR drops (clean sand), resistivity rises and separates (hydrocarbons resisting current), and the density–neutron curves cross over (porosity filled with light fluid). One zone, three independent confirmations.
Chapter 04·Reading the hole

Lithology & porosity logs #

Three tools measure porosity by different physics, and reading them together also identifies the rock and even spots gas.

  • Density log — bombards the rock with gamma rays; bulk density gives porosity if you know the matrix and fluid densities. Also yields the photoelectric factor (PEF), a clean lithology indicator (sandstone ≈1.8, limestone ≈5, dolomite ≈3).
  • Neutron log — measures hydrogen content, a proxy for liquid-filled porosity. Reads low in gas (less hydrogen) — the basis of the gas indicator.
  • Sonic log — travel time of sound; gives porosity and, crucially, the elastic properties used for geomechanics and the seismic well tie (Module 1).

The density–neutron crossover

Plotting density-porosity and neutron-porosity together is one of the most useful reads on the log. In liquid-filled clean rock they overlay. In gas, density reads too-high porosity (gas is very light) while neutron reads too-low (gas has little hydrogen) — they separate in a diagnostic "crossover." Shale does the opposite (neutron reads high from clay-bound water). The crossplot below is how a petrophysicist sorts lithology and fluid at a glance.

Density–neutron crossplot A crossplot of density porosity against neutron porosity with lithology lines for sandstone, limestone, and dolomite, a shale point in the lower right, and a gas effect arrow pushing points up and to the left. neutron porosity → density porosity → sandstone limestone dolomite shale gas effect
The density–neutron crossplot. Lithology lines fan from the origin; a point's position names the rock, shale falls to the lower right, and gas pushes points up and to the left — the same crossover seen on the log track.
Chapter 05·Finding the oil

Resistivity & saturation: Archie's equation #

This is the single most important equation in petrophysics. Archie's equation turns a resistivity reading into water saturation — and therefore into how much of the pore space holds hydrocarbons. Gus Archie worked it out at Shell in 1942; eighty years later it is still the backbone of log analysis.

The logic

Rock grains don't conduct electricity; only the brine in the pores does. So a rock's resistivity depends on how much brine it holds and how that brine is arranged. Two steps:

First, for a fully water-saturated rock, resistivity (Ro) exceeds the brine's own resistivity (Rw) by the formation factor F, which depends only on porosity:

F = Ro / Rw = a / φm   // a ≈ 1, m = cementation exponent ≈ 2

Second, when hydrocarbons replace some brine, resistivity rises further. The resistivity index relates true resistivity (Rt) to water saturation:

Rt / Ro = Sw−n   // n = saturation exponent ≈ 2

Combine them and solve for saturation — the form you will use a thousand times:

Sw = [ (a · Rw) / (φm · Rt) ](1/n)

Everything on the right comes from logs and lab: φ from the porosity logs, Rt from deep resistivity, Rw from a water sample or the SP log, and a/m/n from core. Out comes Sw. Then 1−Sw is the hydrocarbon saturation that feeds straight into STOIIP.

The Pickett plot A log-log plot of true resistivity versus porosity; a water line of slope minus m passes through fully wet points, and parallel lines above it mark constant water saturation, with a hydrocarbon-bearing point plotting off the water line. log porosity φ → log Rt → Sw=100% Sw=50% Sw=20% wet pay (high Rt)
The Pickett plot — Archie drawn graphically. The slope of the water line gives m, parallel lines mark constant Sw, and a hydrocarbon zone plots above the water line. It's how petrophysicists solve for a, m, Rw, and Sw at once.
Where Archie breaks

Archie assumes the only conductor is brine. In shaly sands, clay minerals conduct too, making the rock look wetter than it is and hiding pay. Corrections — Simandoux, Waxman-Smits, dual-water — add a clay-conductivity term. Knowing when a reservoir is shaly enough to need them is a core petrophysical judgment, and it is central to evaluating the clay-rich rocks of many shale plays.

Chapter 06·Finding the oil

NMR & advanced logs #

The triple combo answers most questions; the advanced suite answers the hard ones. The standout is nuclear magnetic resonance (NMR), which measures fluids in the pores directly, independent of the rock matrix.

NMR: seeing the fluids

NMR aligns hydrogen nuclei with a magnetic field, tips them, and times how fast they relax. Fluid in small pores relaxes fast; fluid in large pores relaxes slowly. The distribution of relaxation times (the T₂ distribution) therefore maps the pore-size distribution — and from it you get total porosity split into clay-bound water, capillary-bound (irreducible) water, and free, producible fluid. That free-fluid fraction is what will actually flow, and NMR even yields a permeability estimate — something no other log does directly.

NMR T2 distribution A plot of signal amplitude versus T2 relaxation time on a log scale, with a fast-relaxing peak labeled clay-bound water, a middle peak labeled capillary-bound water, and a slow-relaxing peak labeled free producible fluid, separated by cutoff lines. T₂ relaxation time (log) → bigger pores amplitude clay-bound capillary-bound free / producible T₂ cutoff
NMR splits porosity by pore size. Everything right of the cutoff is producible fluid; everything left is bound and won't flow. This is how NMR estimates permeability and free-fluid volume where Archie alone can't.

Other advanced tools: image logs (a fine resistivity or acoustic picture of the borehole wall) reveal bedding dip, fractures, and breakouts that give the stress direction; dielectric tools help in fresh or unknown-salinity water; spectroscopy tools measure elemental composition for mineralogy. The dipole sonic gives the shear and compressional velocities that feed both the seismic tie (Module 1) and the geomechanical model for fracturing (Module 5).

Chapter 07·Finding the oil

Pressure & fluid sampling #

Logs tell you what is in the rock; formation pressure tells you how the fluids are organized and connected. A wireline formation tester (the original Schlumberger RFT, modern MDT-type tools) sets a probe against the wall, draws a small sample, and measures the formation's pressure at that exact depth — repeated up and down the well.

Gradients and contacts

Plot those pressures against depth and the slope of the line is the fluid density gradient: gas ~0.08 psi/ft, oil ~0.35, water ~0.45. Where two gradient lines intersect is a fluid contact — the gas-oil or oil-water boundary — pinned precisely without ever seeing it on a log. Pressures also reveal compartmentalization: if two sands sit on the same gradient line they are likely in pressure communication; if offset, a sealing barrier separates them — a make-or-break fact for how many wells a field needs.

Pressure-depth plot with fluid contacts Pressure increasing rightward versus depth increasing downward, with a shallow gas gradient, a steeper oil gradient, and a steepest water gradient; the gradient intersections mark the gas-oil contact and the oil-water contact. pressure → depth ↓ gas (0.08) oil (0.35) water (0.45) GOC OWC
Pressures plotted vs depth. Each fluid has its own gradient slope; the kinks where they intersect locate the gas-oil and oil-water contacts exactly — the depths that set the column height in the volumetric calculation.
Chapter 08·Finding the oil

Core analysis #

Logs measure rock properties indirectly; core is the rock itself, cut from the formation and brought to surface. It is expensive and slow, so you take it sparingly — but it is ground truth, and it is what calibrates every log in the field.

  • Routine core analysis (RCA) — porosity, permeability, and grain density on regularly spaced plugs. This is what ties the log-derived porosity to reality and supplies the permeability that no standard log measures.
  • Special core analysis (SCAL) — the hard, slow tests: capillary pressure (the saturation-height function and irreducible water), relative permeability (how oil and water flow together — the heart of recovery prediction), and wettability. SCAL is where the Archie exponents a, m, n actually come from.

The discipline's golden rule: calibrate logs to core. Logs give continuous coverage; core gives truth at points. Tie them and you can trust the logs across the whole field — and across the dozens of wells where you took no core at all. SCAL relative-permeability and capillary-pressure data flow directly into the reservoir simulation of Module 4.

Chapter 09·The lateral & the answer · LATERAL SPINE

Unconventional petrophysics #

Shale breaks the conventional playbook. The reservoir is the source rock; the matrix is nanodarcy; clay and kerogen confuse the standard logs; and the deliverable is not "is there pay" but "where exactly do I land the lateral and is the rock brittle enough to frac." Unconventional petrophysics is its own craft.

What's different

  • TOC from logs. Organic matter is electrically resistive and low-density. The Passey ΔlogR method overlays scaled resistivity and porosity (sonic) curves; where they separate, organic richness is high. This maps TOC continuously without coring every foot.
  • Kerogen confuses porosity. Kerogen reads like porosity to a density log but isn't connected pore space, so raw porosity overstates the producible volume. Corrections are essential.
  • Brittleness & mineralogy. Rock you can frac is brittle (high quartz/carbonate, low clay). Elemental spectroscopy and sonic-derived elastic moduli (Young's modulus, Poisson's ratio) grade frackability — as important as the hydrocarbon content.

Picking the landing zone

Everything converges on choosing the few-foot interval to run the lateral through. The ideal landing zone maximizes a stack of properties at once: organic richness (TOC), oil saturation, porosity, and brittleness, while avoiding clay-rich or water-wet streaks. This is the petrophysical answer to the geological question Module 1 posed.

Selecting the landing zone from logs Four log tracks versus depth in a shale interval: TOC, oil saturation, porosity, and brittleness. A narrow zone where all four are favorable is highlighted as the landing zone, with the planned lateral path drawn through it. TOC oil sat porosity brittleness LANDING planned lateral runs where all four logs peak together
The landing-zone pick: not one log but the overlap of several. The lateral is steered through the narrow interval where organic richness, oil saturation, porosity, and brittleness are all favorable at once — the petrophysical sweet spot.
Connects

This closes the loop opened in Module 1 (why the landing zone matters) and Module 2 (how you steer to it). LWD reads these same curves in real time so the geosteerer keeps the bit in this band. The brittleness number hands directly to the frac design in Module 5.

Chapter 10·The lateral & the answer

Pay & net-to-gross #

The final step turns curves into a number. Not every foot of reservoir counts — only the rock good enough to produce. Net pay is the thickness that passes a set of cutoffs:

  • Shale volume (Vsh) cutoff — too shaly, discard (from GR).
  • Porosity cutoff — below some φ it won't hold or flow enough, discard.
  • Saturation cutoff — above some Sw it produces mostly water, discard.

The ratio of net pay to the gross reservoir interval is the net-to-gross (N/G), a term from the volumetric equation in Module 1. The full petrophysical workflow runs: depth-match the logs → compute Vsh from GR → compute porosity from density/neutron (corrected) → compute Sw from Archie (or a shaly-sand model) → apply cutoffs → sum net pay → average φ and Sw over the pay → hand off to volumetrics and reserves.

The handoff

What leaves petrophysics is a small, consequential table: net pay thickness, average porosity, average water saturation, and a permeability estimate, with their uncertainties. Those numbers are the inputs to the STOIIP calculation and to the reservoir model. Get the petrophysics wrong and every number downstream is wrong with it.

Chapter 11·Reference

Equations & glossary #

The equations of this module

F = a / φm   // formation factor
Sw = [ (a · Rw) / (φm · Rt) ](1/n)   // Archie saturation
φD = (ρma − ρb) / (ρma − ρf)   // density porosity
Vsh ≈ (GR − GRclean) / (GRshale − GRclean)   // shale volume from gamma ray
N/G = net pay / gross reservoir   // net-to-gross

Glossary

TermMeaning
Archie's equationRelates water saturation to resistivity and porosity; the core saturation calculation.
CutoffThreshold (Vsh, φ, Sw) a foot of rock must pass to count as net pay.
InvasionMud filtrate displacing formation fluid near the wellbore.
LWD / wirelineLogging while drilling vs logging on cable after drilling.
NMRNuclear magnetic resonance log; splits porosity into bound and free fluid, estimates permeability.
Net payReservoir thickness good enough to produce, after cutoffs.
Rt / RxoTrue (undisturbed) vs flushed-zone resistivity.
SCALSpecial core analysis — capillary pressure, relative permeability, wettability.
Triple comboGamma ray + resistivity + density-neutron, the standard log suite.
TOC (from logs)Total organic carbon estimated from logs, e.g. by Passey ΔlogR.
SwWater saturation; 1−Sw is hydrocarbon saturation.
End of Module 3

You can now read a triple combo, compute saturation with Archie, recognize gas on a crossplot, read pressures to find contacts, calibrate logs to core, and grade a landing zone for a lateral. Next: Module 4, Reservoir Engineering — how the fluids actually flow, how much you'll recover, and why shale declines so fast.