Geochemistry
Geochemistry is the study of the chemical composition of the Earth and other solid planetary bodies, including the distribution, abundance, and cycling of chemical elements through rocks, fluids, and organic matter — and in the petroleum industry specifically, the discipline that applies chemical analytical techniques to characterize source rock quality and maturity, correlate crude oils and condensates to their source formations, reconstruct the thermal and burial history of sedimentary basins, and assess the timing and volume of petroleum generation, migration, and accumulation that determine whether a prospect will contain commercial quantities of hydrocarbons; source rock geochemistry determines the total organic carbon (TOC) content that quantifies how much organic matter is present, the Rock-Eval pyrolysis that measures how much hydrocarbon the rock has generated and how much generation potential remains, the vitrinite reflectance (Ro) that calibrates thermal maturity against the oil and gas generation windows, and the biomarker fingerprinting that allows oil samples to be matched to their source formations and migration pathways, providing the foundation for understanding whether a basin has functional petroleum systems capable of sourcing commercial accumulations.
Key Takeaways
- Total organic carbon (TOC) measurement quantifies the organic richness of potential source rocks by combusting a weighed powdered sample and measuring the CO2 and CO produced, expressed as weight percent of organic carbon in the rock — the threshold for a viable source rock is generally accepted as TOC greater than 0.5 weight percent for carbonate source rocks and greater than 1.0 weight percent for clastic source rocks, with excellent source rocks having TOC values of 2 to 5 percent and world-class prolific source rocks (Bakken, Vaca Muerta, Monterey) exceeding 10 to 15 percent TOC; the TOC measurement requires removing inorganic carbonate carbon before combustion (by acidification with hydrochloric acid) to measure only organic carbon, and the result reflects current organic content after any thermal generation that has expelled generated hydrocarbons, meaning a mature source rock that has expelled most of its generated oil may have lower residual TOC than an immature source rock of originally lower richness.
- Rock-Eval pyrolysis is the standard geochemical screening tool for source rock characterization that heats a small powdered sample through a programmed temperature ramp in an inert atmosphere, measuring the mass of hydrocarbons released at successive temperature intervals — S1 (free hydrocarbons already present in the rock, released below 300°C) quantifies the hydrocarbon already generated and potentially retained, S2 (hydrocarbons generated by cracking of remaining kerogen, released between 300 and 550°C) quantifies remaining generation potential, S3 (CO2 generated during pyrolysis, related to oxygen-rich kerogen) relates to kerogen type, and Tmax (the temperature at maximum S2 generation rate) provides a thermal maturity indicator independent of vitrinite presence; the hydrogen index (HI = S2/TOC × 100, in mg HC/g TOC) decreases as kerogen matures and generates oil, the oxygen index (OI = S3/TOC × 100) decreases as kerogen matures and loses oxygen, and the production index (PI = S1/(S1+S2)) increases as a source rock generates oil and fills its pores with retained generated hydrocarbons.
- Vitrinite reflectance (Ro) measurement uses the optical reflectance of vitrinite particles (fragments of woody plant material preserved in sedimentary organic matter) under incident white light in oil immersion, expressed as percent reflectance relative to calibration standards — the reflectance increases irreversibly as vitrinite is heated during burial, making Ro a proxy for the maximum paleotemperature experienced by the rock regardless of subsequent uplift and cooling; the oil generation window spans approximately Ro = 0.5 to 1.3%, with peak oil generation at Ro = 0.7 to 1.0%, wet gas and condensate generation at Ro = 1.0 to 1.5%, and dry gas generation at Ro greater than 1.5%; calibration of burial-temperature history models against measured Ro profiles in wells provides the basin thermal history reconstruction that predicts the timing and depth of petroleum generation for prospect risk assessment.
- Biomarker geochemistry uses molecular fossils — complex organic molecules derived from biological precursors that survive diagenesis and catagenesis with structural features diagnostic of the organisms that produced them — to correlate crude oil samples to their source formations and to distinguish oils from different source rocks in commingled production; hopanes (derived from bacterial hopanoids) and steranes (derived from eukaryotic sterols, particularly cholesterol and phytosterol) are the primary biomarker classes used in oil-source rock correlation, with the relative abundance of C27, C28, and C29 steranes reflecting the biological input (C27 dominant in marine carbonate sources, C29 dominant in terrestrial/lacustrine sources); the configuration ratios of steranes and hopanes (alpha-alpha-alpha/20S versus 20R epimers, C31 22S/22R hopane ratios) provide maturity parameters that evolve predictably with increasing thermal stress, providing independent maturity calibration that complements vitrinite reflectance; oil-to-oil and oil-to-source correlation using biomarker fingerprinting is essential for understanding reservoir charge history in complex basins with multiple potential source intervals.
- Stable isotope geochemistry measures the ratio of heavy to light isotopes of carbon (13C/12C, expressed as delta-13C in per mil relative to the Vienna Pee Dee Belemnite standard), hydrogen (2H/1H), and sulfur (34S/32S) in petroleum and source rock samples as fingerprints of source organic matter type and thermal maturity — marine carbonate-sourced oils are generally isotopically heavier (delta-13C between -26 and -29 per mil) than terrestrially-sourced oils (delta-13C between -29 and -33 per mil) because marine photosynthesis preferentially incorporates 13C relative to terrestrial plants; the isotopic composition of methane from thermogenic versus biogenic sources differs systematically (biogenic methane is isotopically lighter, delta-13C below -55 per mil, while thermogenic methane is heavier, delta-13C between -25 and -50 per mil), allowing gas play type identification from geochemical analysis of gas samples from wells or seeps before drilling is committed.
Fast Facts
The Bakken Shale of the Williston Basin is one of the most extensively geochemically characterized source rocks in North America, with average TOC values of 10 to 12 weight percent in the upper and lower Bakken members (some cores exceeding 20 percent), HI values of 400 to 600 mg HC/g TOC in immature samples indicating Type II oil-prone marine algal kerogen, and vitrinite reflectance values of 0.6 to 0.9 percent across the productive fairway confirming peak oil generation maturity. The Bakken's prodigious oil generation — estimated at 300 to 500 billion barrels total generation — has charged both the Bakken itself (unconventional tight oil) and underlying conventional Mississippian carbonate reservoirs throughout the Williston Basin. Petroleum geochemistry was instrumental in demonstrating that the Bakken was the source for Williston Basin conventional production before horizontal drilling made the Bakken itself the target, fundamentally changing the basin's exploration and development strategy.
What Is Geochemistry?
Before a drill bit turns, geochemistry answers the most fundamental question in petroleum exploration: is there a functioning petroleum system here? That question requires knowing whether organic-rich source rocks were deposited, whether they have been buried to sufficient depth and temperature to generate oil or gas, and whether that generated petroleum has a migration pathway to a trap. None of these questions can be answered from seismic data or well logs alone — they require chemical analysis of rock and fluid samples that carries the preserved fingerprints of geological history.
A geochemist working on a frontier basin examines rock cuttings and core from the earliest wells with a focused set of questions: How much organic matter is present (TOC)? What type of kerogen is it — oil-prone Type II marine or gas-prone Type III terrestrial? How thermally mature has it become — is it in the oil window, the gas window, or still immature? Has it generated hydrocarbons yet? These measurements, combined with burial history modeling calibrated against maturity profiles, build the quantitative petroleum system model that tells explorationists whether the basin has generated petroleum at all — the most basic test a prospect must pass.
Source Rock Assessment and Basin Modeling
Kerogen classification into Types I, II, and III (and the mixed Type II/III) uses the hydrogen index and oxygen index from Rock-Eval pyrolysis to position source rocks on the Van Krevelen diagram (a plot of HI versus OI that mirrors the H/C versus O/C atomic ratio plot of classical kerogen characterization) — Type I kerogen (lacustrine algae, HI greater than 600) generates waxy crude oil and is characteristic of lake-deposited source rocks like the Green River Formation; Type II kerogen (marine algae and planktonic material, HI of 300 to 600) generates conventional crude oil and is the dominant kerogen type in productive marine basins from the Devonian to the Cretaceous; Type III kerogen (higher plant material, HI below 150) generates primarily gas with minor waxy condensate and characterizes coal measure sequences and deltaic systems; the kerogen type determines the expected product of thermal generation and therefore what petroleum phases (oil, condensate, or dry gas) a prospect will be charged with if the source rock is mature.
1D basin modeling uses temperature-time integration (the Easy%Ro algorithm or equivalents from Burnham and Sweeney) to calculate the thermal maturity evolution of a source interval from burial through any subsequent inversion or uplift, calibrating the modeled maturity against measured vitrinite reflectance values in the well to validate or adjust the thermal history model; the validated thermal history model predicts the timing of petroleum generation (when the source entered the oil window during burial) relative to the timing of trap formation (when the structural or stratigraphic trap closed to retain migrating petroleum), a timing match being a prerequisite for trap filling; basins where trap formation postdates peak generation risk failure because generated petroleum migrated through before the trap existed to capture it — a charging risk that geochemistry can identify before expensive exploration wells are drilled.
Geochemistry Across International Jurisdictions
Canada (AER / WCSB): WCSB source rock geochemistry has established the Devonian Duvernay Formation (a prolific Type II marine carbonate-organic-rich source rock with TOC of 3 to 10 percent, HI of 300 to 500, and Ro of 0.8 to 1.4 percent in the liquids-rich fairway) as the primary source for both conventional light oil in Devonian pinnacle reef traps and the unconventional Duvernay shale play in central Alberta; AER's mandatory core analysis program for exploration wells in the WCSB requires geochemical characterization of source intervals including TOC and Rock-Eval pyrolysis as part of the well completion submission, building the basin-wide geochemical database used by operators and AER's own petroleum system assessments; the Athabasca oil sands geochemistry — characterized by biodegraded Type II marine oil with extremely high viscosity (API gravity below 10°), low sulfur, and distinctive 25-norhopane biomarker signatures of biodegradation — has been traced to Devonian source rocks in the deep basin to the west using biomarker correlation.
United States (API / BSEE): US unconventional resource plays have been fundamentally characterized by geochemistry — the Eagle Ford Shale (Type II marine kerogen with average TOC of 2 to 8 percent, Ro of 0.6 to 1.8 percent across the oil/condensate/dry gas windows from northeast to southwest across the Texas play), the Haynesville Shale (Type II marine carbonate-organic-rich with TOC of 2 to 5 percent, deeply buried to Ro of 1.6 to 2.5 percent in the dry gas window), and the Permian Basin's Wolfcamp/Bone Spring/Spraberry source-reservoir system (Type II lacustrine-marine mixed kerogen, multiple stacked source-reservoir pairs) have all been mapped geochemically to define play fairways, characterize lateral maturity variations, and predict the oil-versus-gas phase of production before development drilling commenced; USGS resource assessments for unconventional plays use geochemical characterization of source quality and maturity as a primary input to technically recoverable resource volume estimates.