Crude Oil Genesis — Kerogen, Windows, and Why Grades Differ

Crude oil is not a single molecule and not a single market. It is a geological product of burial, heat, and time — then a commercial product sorted by density, sulfur, and logistics. Understanding genesis clarifies why Brent, naphtha, and freight move together more often than coincidence suggests.

From organic mud to kerogen

Most conventional oil starts as organic-rich mud deposited in low-oxygen marine or lacustrine settings. Algae, plankton, and bacterial remains accumulate faster than they oxidize. Early diagenesis (shallow burial) converts that organic matter into kerogen — a solid, insoluble macromolecular residue locked in the source rock.

Kerogen is typed by origin. Type I (lacustrine algal) and Type II (marine planktonic) are the classic oil-prone kerogens. Type III (terrestrial woody) is more gas-prone. The important operational point: oil is generated when kerogen is cracked by heat during deeper burial, not when it is simply compressed.

The oil window

Petroleum geologists describe generation with a thermal window. As a rule of thumb — and always site-dependent — significant oil generation begins around roughly 60°C and remains productive into roughly 160°C burial temperatures (the so-called oil window). Below that, kerogen is immature. Above it, oil cracks further toward wet gas and dry gas (the gas window).

These temperatures map to burial depth only through local geothermal gradient. A hot basin reaches the oil window shallower than a cold one. Timing matters commercially: source rocks that entered the window after trap formation can charge reservoirs; those that generated before seals existed often leak or biodegrade.

Primary migration moves hydrocarbons out of the fine-grained source into carrier beds. Secondary migration drives them along pressure and buoyancy gradients into traps — structural (anticlines, faults), stratigraphic (pinch-outs, reefs), or combination traps. Cap rock integrity and charge volume set recoverable volumes; seismic and well control refine them. Nothing here invents a global “average” recovery factor — that is field-specific engineering, not encyclopedia folklore.

Why crude grades are not fungible

Once produced, crude is assayed. Two properties dominate price differentials:

1. Density (API gravity). Lighter crudes yield more naphtha and middle distillates in a simple atmospheric cut; heavier crudes need more conversion capacity.
2. Sulfur. Sweet crudes (low sulfur) are cheaper to refine into low-sulfur fuels under modern specifications. Sour crudes demand desulfurization and can carry metal contaminants.

Brent (North Sea light sweet complex, priced as a waterborne benchmark) and WTI (U.S. midcontinent light sweet, inland logistics via Cushing) are both light-sweet references — yet they diverge when pipeline constraints, export policy, or regional demand shift. Urals is a medium sour Russian export blend. Its discount (or occasional premium) versus Brent is not a moral statement; it is sulfur, density, sanction frictions, and destination refining economics. Estimates of “typical” Urals discounts change with policy and freight — treat static spreads as estimated, not eternal.

These grade differences feed directly into crack spreads, the refiner’s margin between crude input and product slate. A light sweet barrel and a heavy sour barrel are not interchangeable feedstock for the same units without yield and cost adjustments — which is why Market Wire tracks Brent beside WTI and an Urals estimate rather than collapsing everything into one number.

From geology to the terminal

Genesis also explains volatility clusters. When a basin’s production is heavy and sour, refining bottlenecks amplify price moves in products more than in the crude marker. When light sweet is abundant, naphtha and gasoline cracks behave differently (see naphtha). Shipping constraints — covered in freight economics — can temporarily outweigh chemistry.

The live Brent card on this page is the market’s shorthand for “light sweet waterborne.” It does not measure kerogen maturity. It prices the result of that geology after decades of exploration, midstream build-out, and refining configuration. Read the geology to interpret the ticker; use the ticker to test whether today’s differential still matches the chemistry story.

Practical reading list for operators

• Source-rock maturity and trap timing beat slogans about “peak oil” when evaluating a basin.
• Grade differentials are a refining and logistics problem first, a headline problem second.
• Cross-check liquids with thermal coal and gas only when substitution is real at the burner tip — otherwise correlations are noise.

Oil’s origin story is slow geology. Its price story is fast markets. Pedia exists to keep those two clocks from being confused.