Petroleum Systems Modeling: Definition, Basin Modeling, and Exploration Risk

What Is Petroleum Systems Modeling?

Petroleum systems modeling (PSM, also called basin modeling) is the quantitative simulation of the geological processes that generate, expel, migrate, and accumulate hydrocarbons over geological time — used to predict the volume, type, and charge timing of petroleum at prospect and basin scale. A petroleum systems model integrates the burial history of the source rock (backstripped from well logs and seismic data), the thermal history (paleo-heat flow from geodynamic models), the kinetics of organic matter transformation to oil and gas (kerogen cracking reactions), the expulsion efficiency from the source rock, the migration pathways through carrier beds and faults, and the timing of trap formation relative to charge. The model outputs the predicted oil column height in a prospect, the oil vs gas ratio of the charge, the timing of filling and spillage, and whether the trap was charged before or after structural events that might have destroyed the seal. Petroleum systems modeling is the primary risk assessment tool for frontier and deep-water exploration, where well control is sparse and the geological unknowns must be modelled rather than measured.

Modeling Workflow and Key Parameters

The PSM workflow begins with structural restoration and backstripping: the present-day burial depth of each stratigraphic layer is reversed through time to reconstruct the depth, temperature, and pressure history of the source rock. Decompaction (accounting for porosity loss with burial) and sea level corrections produce the paleo-burial history at each well location. The thermal model converts burial depth to temperature using either a constant heat flow (simple conduction model) or a dynamic heat flow history derived from geodynamic models (rifting events produce heat flow spikes; subsequent thermal subsidence cools the lithosphere over tens of millions of years). Temperature history drives the maturity model: Easy%Ro (Sweeney and Burnham, 1990) or LLNL kinetic models convert time-temperature history to vitrinite reflectance equivalent Ro%, which is the industry standard maturity indicator calibrated against measured Ro from core and cuttings.

The generation model applies kerogen reaction kinetics to the source rock's TOC, HI (hydrogen index), and maturity to calculate the volume of oil and gas generated over geological time. Type I kerogen (algal-lacustrine, high HI ~900 mgHC/gTOC) generates primarily oil; Type II (marine shale, HI 300–600) generates oil then gas; Type III (terrestrial/coal, HI < 200) generates primarily gas. Expulsion efficiency — the fraction of generated hydrocarbons that actually leaves the source rock as free-phase fluid rather than remaining adsorbed — typically ranges from 20–80% for oil and 50–95% for gas. Migration modeling traces expelled hydrocarbons through the carrier system to traps using pressure-driven Darcy flow (for basin-scale flux simulation) or geometric ray tracing (faster, for pathway mapping) — identifying which traps receive charge from which kitchen areas and in what volumes.

Petroleum Systems Modeling Synonyms and Related Terminology

Petroleum systems modeling is also referred to as:

• Basin modeling — the more general geological term; PSM is the petroleum-focused application of basin modeling that specifically tracks hydrocarbon generation and migration
• Burial history modeling — the backstripping and decompaction component that reconstructs the depth-time history of source and reservoir rocks
• Source rock maturity modeling — the specific sub-discipline focused on predicting vitrinite reflectance, transformation ratio, and generation timing from burial and thermal history
• Migration modeling — the component that tracks expelled hydrocarbons from source to trap; can be run independently of the generation model with user-specified HC volumes

Related terms: Source Rock, Vitrinite Reflectance, Plate Tectonics, Trap

Frequently Asked Questions About Petroleum Systems Modeling

How is source rock richness measured and what makes a good source rock?

Source rock richness is characterised by three measurements from Rock-Eval pyrolysis: TOC (total organic carbon, in wt%), S1 (free hydrocarbons already in the rock, mg HC/g rock), S2 (crackable kerogen, mg HC/g rock), and Tmax (temperature of maximum S2 generation — a maturity indicator). The hydrogen index (HI = S2/TOC × 100, in mgHC/gTOC) indicates kerogen type: HI > 700 = Type I (oil-prone algal), HI 300–600 = Type II (marine shale, oil and gas), HI < 200 = Type III (terrestrial gas-prone). The oil generation potential of a source rock is approximately S2/8 barrels of oil per tonne of rock — a rich marine shale with TOC = 5% and HI = 400 has S2 ≈ 20 mgHC/g and potential of 2.5 bbl oil/tonne. Minimum thresholds for commercial petroleum source rocks: TOC > 0.5% for carbonates (dense matrix reduces HI minimum), TOC > 1% for shales. World-class source rocks (Kimmeridge Clay in the North Sea, Vaca Muerta in Argentina, Bazhenov in West Siberia, Monterey Shale in California) have TOC of 5–20% and HI of 400–900, representing enormous generation potential. The Jurassic Kimmeridge Clay (TOC 5–15%, HI 400–600) sourced the majority of the North Sea's 40+ billion barrels of recoverable oil reserves.

What is the critical moment in a petroleum system and why does it matter?

The critical moment is the point in geological time at which the petroleum system is most likely to be functioning as an integrated system — source rock generating and expelling hydrocarbons, migration pathways open, traps intact with seals in place. It is typically the time of maximum source rock burial (peak generation) or, in uplift-dominated basins, just before major uplift began. All elements must be functioning simultaneously for accumulation to occur: if the trap formed after the critical moment, no hydrocarbons fill it; if the seal was breached before it, the trap was never filled; if migration pathways closed, the charge could not reach the trap. The critical moment map for a basin shows where and when the "petroleum system machine" was running at maximum efficiency, directing exploration toward prospects favourably positioned at the critical moment rather than those favourably positioned only today.

What are the main differences between 1D, 2D, and 3D petroleum systems models?

1D petroleum systems modeling (single well or pseudo-well) reconstructs the burial and thermal history at a single geographic location — giving the maturity, generation timing, and expulsion history at one point in the basin. 1D models are fast to build and calibrate, making them ideal for initial source rock assessment at well locations, screening for thermal history consistency, and evaluating generation risk in nearby prospects. They cannot model lateral migration or charge distribution across the basin. 2D models (cross-sections or profiles) add the spatial dimension along a geological cross-section — they model how heat flow varies laterally (e.g., near a salt diapir that disrupts conductive heat flow), how migration pathways channel hydrocarbons from kitchens to traps along carrier beds, and how fault transmissibility controls whether charge crosses structural barriers. 2D models are significantly more informative than 1D for migration pathway analysis but require careful structural restoration of the cross-section through time. 3D models represent the full volumetric petroleum system — they simulate migration across the entire basin in three dimensions, accounting for lateral and vertical carrier bed geometry, structural dip direction, and fault network connectivity. 3D PSM is the highest-fidelity tool but requires enormous input data (a 3D seismic-derived structural framework, paleogeographic reconstruction, and regional heat flow model) and weeks to months of expert interpretation and model building. 3D models are used primarily in frontier basin assessment and in mature basins where charge distribution to multiple simultaneous prospects requires integrated analysis.

Why Petroleum Systems Modeling Matters in Oil and Gas

Petroleum systems modeling is the exploration geoscientist's primary tool for turning geological observations into quantitative risk assessments — transforming the question "is there oil here?" from a qualitative judgment into a probabilistic analysis with defensible charge volumes and risk factors. In frontier basins with no wells, PSM provides the only method to evaluate whether source rocks exist, whether they are mature, and whether hydrocarbons could have migrated to the prospect being evaluated. In mature basins, PSM quantifies residual charge risk for new plays in deeper or previously untested horizons. The commercial impact is enormous: exploration failure rates in well-constrained basins average 30–40% even with modern 3D seismic, and charge failure (source rock immature, migration pathways don't reach the trap, or timing mismatch) accounts for 20–30% of dry holes. Eliminating high-charge-risk prospects through rigorous PSM before drilling can save hundreds of millions of dollars annually in a major exploration programme — making petroleum systems modeling one of the highest-return analytical investments in the upstream petroleum industry.