Kerogen
Kerogen is the insoluble, high-molecular-weight solid organic matter dispersed in fine-grained sedimentary rocks that serves as the precursor to oil and gas upon burial and thermal maturation, classified into four types by hydrogen-to-carbon and oxygen-to-carbon ratios on the van Krevelen diagram: Type I (algal, oil-prone), Type II (marine, oil and gas), Type IIS (sulfur-rich Type II with early generation), and Type III (terrestrial humic, gas-prone), with Type IV (inertinite) lacking generation potential.
Key Takeaways
- Type I kerogen, derived primarily from lacustrine algae, has the highest initial H/C ratio (above 1.5) and generates waxy crude oils almost exclusively, with the Green River Formation of the Uinta Basin being the classic example.
- Type II kerogen, sourced from marine algae, bacteria, and zooplankton deposited in anoxic basins, generates both oil and gas and accounts for most of the world's conventional oil reserves including Middle East carbonates and North Sea source rocks.
- Type III kerogen, derived from land-plant organic material, has low H/C and high O/C ratios and generates primarily dry gas and condensate, making it important for conventional gas and coalbed methane plays.
- Kerogen pyrolysis by Rock-Eval analysis yields S1 (free hydrocarbons), S2 (generative potential), and Tmax (peak generation temperature), which together define the hydrogen index and production index used to classify kerogen type and maturity.
- In organic-rich shales such as the Eagle Ford and Barnett, kerogen contains nanopore networks that provide significant storage capacity for adsorbed gas, making kerogen porosity a critical parameter in shale gas resource estimation.
Fast Facts
Kerogen accounts for the vast majority of organic carbon in sedimentary rocks; bitumen and oil represent only a small fraction of total organic matter. Total organic carbon (TOC) content, expressed as weight percent, measures kerogen abundance. Good source rocks typically contain 1 to 4 wt% TOC, while world-class source rocks such as the Duvernay and Vaca Muerta may exceed 10 wt% TOC. Kerogen is insoluble in organic solvents, which distinguishes it from bitumen (soluble asphaltenes and resins) and light hydrocarbons.
Tip: When interpreting Rock-Eval data, always cross-plot hydrogen index (HI) against oxygen index (OI) on a van Krevelen-style diagram to confirm kerogen type before using S2 data for resource calculations. High-maturity samples show artificially low HI regardless of original kerogen type, so maturity-corrected HI values are needed for resource estimates in deeply buried plays.
What Is Kerogen
Kerogen is the name given to the complex macromolecular organic material that remains after sedimentary organic matter is processed by diagenesis and rendered insoluble in common organic solvents. It forms during the early burial of organic-rich sediments when microbial activity and geochemical condensation reactions transform biopolymers from algae, bacteria, and plant tissues into a cross-linked, high-molecular-weight solid. This transformation progressively strips away functional groups containing oxygen and nitrogen, leaving a carbon-hydrogen framework that becomes the raw material for petroleum generation at greater depths.
The term was coined by Scottish geologist Alexander Crum Brown and colleagues in the 1800s but was formalized in modern petroleum geochemistry by Tissot and Welte in the 1970s. Kerogen forms the organic carbon content measured as total organic carbon (TOC), and its concentration and type together determine whether a rock qualifies as a source rock capable of generating commercial quantities of hydrocarbons.
How Kerogen Works
Kerogen generation of petroleum proceeds through three stages defined by temperature and burial depth. In the early diagenetic stage (below approximately 50 degrees Celsius), microbial degradation dominates and biogenic methane may form, but no thermal cracking occurs. In the catagenetic stage (50 to 150 degrees Celsius), increasing temperature progressively breaks the weaker carbon-carbon and carbon-heteroatom bonds in the kerogen network, releasing liquid hydrocarbons (oil) and associated gas. This is the oil window, corresponding to vitrinite reflectance of 0.6% to 1.35% Ro. Above 1.35% Ro, oil remaining in the source rock cracks to wet gas and condensate. Above 2.0% Ro in the metagenetic stage, only dry methane remains stable.
Rock-Eval pyrolysis is the standard laboratory tool for characterizing kerogen. A small rock sample is heated in an inert atmosphere; the S1 peak represents volatilized free hydrocarbons already present, S2 represents hydrocarbons generated by pyrolytic cracking of kerogen, and Tmax is the temperature of peak S2 generation. The hydrogen index (HI = S2/TOC x 100, in mg HC/g TOC) and oxygen index (OI = S3/TOC x 100) place the kerogen on the van Krevelen diagram, revealing its type and stage of maturity.
In unconventional shale reservoirs, kerogen plays a second role beyond generation: organic-hosted nanopores within the kerogen matrix provide significant storage volume for adsorbed and free gas. FIB-SEM imaging of shales like the Barnett and Haynesville shows pore diameters of 5 to 100 nanometres within kerogen particles, and digital rock physics workflows integrate these observations into permeability and storage models used for reserves estimation.
Kerogen Across International Jurisdictions
In Canada and the WCSB, kerogen characterization is central to evaluating the Devonian Duvernay Formation, which contains Type II marine kerogen with TOC values typically between 1 and 8 wt%, making it one of North America's highest-quality liquid-rich shale source rocks. The Alberta Energy Regulator (AER) publishes open-file data on Duvernay geochemistry. The Jurassic Nordegg and Lower Cretaceous Garbutt members contain Type II and Type IIS kerogen. Montney Formation tight-gas reservoirs are sourced from adjacent Type II shale members in the underlying Doig and Montney. Kerogen type and TOC underpin Alberta's resource evaluations submitted with AER licence applications and annual reserve reports.
In the United States, the Energy Information Administration (EIA) incorporates kerogen-type data into its shale resource assessments for plays including the Eagle Ford (Type II marine, high HI, oil and condensate window), Marcellus (Type II, gas-condensate at high maturity), Permian Basin Wolfcamp (mixed Type II and III), and the Uinta Basin Green River Formation (Type I lacustrine kerogen, famous for oil shale retorting research). The USGS uses TOC maps and kerogen type when publishing undiscovered resource assessments under the National Oil and Gas Assessment program.
In Norway, the Norwegian Offshore Directorate (formerly Sodir) maintains geochemical databases for North Sea source rocks. The Upper Jurassic Draupne Formation contains high-quality Type II kerogen with TOC commonly above 5 wt% and HI values exceeding 400 mg HC/g TOC in well-preserved marine facies. This kerogen sourced the giant Ekofisk, Statfjord, and Oseberg fields. The Åre Formation in the Norwegian Sea contains Type III terrestrial kerogen from deltaic coal-bearing sequences, which sourced gas in the Ormen Lange and Kristin fields.
In the Middle East and within Saudi Aramco's operational scope, Type II marine kerogen in the Jurassic Hanifa, Tuwaiq Mountain, and Diyab formations sourced the super-giant Ghawar and Arabian Gulf carbonate fields. These source rocks are relatively lean in TOC (1 to 3 wt%) but generated enormous volumes due to their vast geographic extent and long generation history. The Silurian Qusaiba hot shale in Saudi Arabia and the Paleozoic section in the Rub' al Khali basin contain mixed Type II and III kerogen and are assessed as sources for unconventional gas targets by Saudi Aramco's exploration team.
Synonyms and Related Terminology
Kerogen is often discussed alongside vitrinite reflectance, the primary thermal maturity indicator used to determine where in the kerogen conversion sequence a source rock sits. Source rock is the broader term for the formation that contains kerogen in sufficient quantity and quality to generate petroleum. Total organic carbon (TOC) is the quantitative measure of kerogen abundance. Bitumen refers to the soluble fraction of organic matter that has already been generated from kerogen. The van Krevelen diagram, hydrogen index, and oxygen index are the analytical tools used to classify kerogen type from Rock-Eval data.
FAQ
What is the difference between kerogen and bitumen?
Kerogen is insoluble in organic solvents and represents the uncracked, high-molecular-weight precursor material still locked in the rock matrix. Bitumen is the soluble fraction, comprising asphaltenes, resins, and heavy aromatic compounds that have already been generated from kerogen or migrated into the rock from elsewhere. During Rock-Eval analysis, free bitumen contributes to the S1 peak while intact kerogen contributes to the S2 peak. In shale reservoirs, bitumen partially fills pores previously occupied by kerogen and retains some residual porosity after generation.
How does kerogen type affect shale oil recovery?
Kerogen type controls both the quantity and quality of oil generated. Type I kerogen produces waxy, paraffinic crudes with high API gravity but high pour points; Type II kerogen generates lighter, more aromatic oils that flow more easily. Type III kerogen primarily generates gas and yields very little liquid. In in-situ upgrading pilot projects (such as Shell's ICP process in the Green River Formation), Type I kerogen's high HI means more oil is available per tonne of rock, but the waxy composition requires thermal processing to achieve pipeline-quality crude.
Why Kerogen Matters
Kerogen type and abundance are the foundational inputs to every petroleum system model. Without sufficient TOC, no generation occurs regardless of burial depth; without the right kerogen type, gas-prone source rocks will not produce economic oil. Exploration teams use kerogen data to rank prospects, define fairway boundaries, and calibrate migration models that predict where generated hydrocarbons accumulated. In the unconventional shale revolution, kerogen transitioned from a passive indicator to an active reservoir component: organic porosity within kerogen matrices stores the gas that shale wells produce. Resource estimations for tight-oil and shale-gas plays rely on kerogen-derived porosity models, making kerogen characterization as important to production engineering as it is to exploration geology.