5.5 Petroleum geochemistry

Origins of petroleum

Petroleum forms over millions of years as organic matter buried in sedimentary basins undergoes decomposition and chemical transformation. Understanding these origins helps predict where oil and gas accumulate, what quality they'll be, and how best to extract them.

Source rock characteristics

Effective source rocks are organic-rich, fine-grained sedimentary rocks like shales and mudstones. Their fine grain size limits water circulation, which helps preserve organic matter before it can be oxidized.

• Total organic carbon (TOC) content in effective source rocks typically ranges from 1–10%
• Depositional environment strongly influences source rock quality: marine, lacustrine, and terrestrial settings each produce different organic matter types
• Anoxic conditions during deposition are especially important because oxygen-depleted bottom waters prevent microbial breakdown of organic material

Kerogen types

Kerogen is the insoluble organic matter in source rocks, and its type determines what kind of hydrocarbons a source rock can generate. Classification relies on the Van Krevelen diagram, which plots Hydrogen Index (HI) vs. Oxygen Index (OI).

• Type I: Derived primarily from algal material. High HI, highly oil-prone. Common in lacustrine settings.
• Type II: Originates from marine organic matter. Moderate-to-high HI, generates both oil and gas.
• Type III: Comes from terrestrial plant material (woody, cellulosic). Low HI, primarily gas-prone.
• Type IV: Residual, highly oxidized organic matter with very low hydrocarbon generation potential.

Thermal maturation process

As source rocks are progressively buried, increasing temperature drives the conversion of kerogen into hydrocarbons. This happens in three stages:

1. Diagenesis (shallow burial, low temperatures): Biological activity and low-temperature chemical reactions convert organic matter into kerogen. Biogenic methane may form.
2. Catagenesis (the "oil window," roughly 60–120°C): Thermal cracking of kerogen generates most oil and wet gas. This is the main stage of petroleum generation.
3. Metagenesis (high temperatures, >150°C): Remaining kerogen and previously generated oil crack further, producing primarily dry gas (methane).

Vitrinite reflectance ($\%R_o$) is the most widely used thermal maturity indicator. Values around 0.6–1.3 $\%R_o$ correspond to the oil window, while values above ~2.0 indicate the dry gas zone.

Petroleum composition

Petroleum is a complex mixture of organic compounds whose molecular makeup reflects its source, thermal history, and any alteration it has undergone. Compositional analysis informs refining processes and helps geochemists trace oil back to its origin.

Hydrocarbons vs. non-hydrocarbons

Hydrocarbons (compounds of only C and H) form the bulk of most crude oils:

• Saturated hydrocarbons: n-alkanes (paraffins) and cycloalkanes (naphthenes) typically dominate
• Aromatic hydrocarbons: benzene, toluene, xylenes, and polycyclic aromatic hydrocarbons (PAHs)

Non-hydrocarbon components, though present in smaller amounts, significantly affect oil quality:

• NSO compounds: Molecules containing sulfur, nitrogen, or oxygen. High sulfur makes "sour" crude, which is more expensive to refine.
• Asphaltenes and resins: High-molecular-weight, polar fractions that influence viscosity and can cause production problems
• Trace metals: Vanadium (V) and nickel (Ni) concentrate in asphaltenes and can poison refinery catalysts

Biomarkers in petroleum

Biomarkers are molecular fossils, organic compounds whose carbon skeletons can be traced back to specific biological precursors. They survive thermal maturation with enough structural integrity to be diagnostic.

• Hopanes originate from bacteriohopanepolyols in bacterial cell membranes
• Steranes derive from sterols in eukaryotic organisms (algae, higher plants)
• The pristane/phytane ratio ($Pr/Ph$) reflects redox conditions in the depositional environment: low ratios suggest anoxic conditions, high ratios suggest oxic conditions
• Biomarker ratios change systematically with increasing thermal maturity, making them useful as both source and maturity indicators

Elemental analysis

• Carbon and hydrogen make up the vast majority of petroleum by weight (typically 83–87% C, 10–14% H)
• Sulfur content varies widely (0.1% to >5%) and is a primary factor in crude oil classification and pricing
• Nitrogen compounds affect oil stability and create challenges during refining (catalyst poisoning)
• Oxygen-containing compounds (naphthenic acids, phenols) influence acidity and corrosion potential
• The V/Ni ratio serves as a geochemical indicator of source rock type and depositional environment: marine source rocks tend to produce oils enriched in V relative to Ni

Migration and accumulation

After generation in source rocks, hydrocarbons must migrate to and accumulate in reservoir rocks to form exploitable deposits. Geochemical techniques help reconstruct these pathways and predict where accumulations are likely.

Primary vs. secondary migration

Migration happens in two stages:

1. Primary migration: Expulsion of hydrocarbons from the fine-grained source rock. This is the harder step because source rocks have very low permeability. Mechanisms include pressure-driven bulk flow, molecular diffusion, and dissolution in formation water.
2. Secondary migration: Movement through more permeable carrier beds toward reservoir rocks. Buoyancy (hydrocarbons are less dense than formation water) and capillary pressure gradients are the main driving forces.

Migration efficiency depends on rock permeability, hydrocarbon saturation, and the continuity of migration pathways. Vertical migration commonly occurs along faults and fractures.

Traps and seals

A trap is any geometric arrangement of rock that stops migrating hydrocarbons and allows them to accumulate.

• Structural traps: Formed by tectonic deformation. Anticlines (arched folds) and fault traps are the most common.
• Stratigraphic traps: Result from lateral changes in rock properties, such as pinch-outs (where a permeable layer thins to zero) or unconformities.
• Combination traps: Involve both structural and stratigraphic elements.

A seal (or cap rock) is the impermeable layer above the trap that prevents hydrocarbons from escaping. Shales and evaporites are the most effective seals. Seal quality is governed by capillary entry pressure: the pressure a hydrocarbon column must exert to force its way through the seal's pore throats.

Reservoir rock properties

• Porosity determines how much fluid a rock can store. Primary porosity forms during deposition (intergranular pore space), while secondary porosity develops later through dissolution or fracturing.
• Permeability controls how easily fluids flow through interconnected pores. High porosity without permeability means hydrocarbons are trapped but can't be produced.
• Wettability describes whether the rock surface preferentially attracts water or oil, affecting fluid distribution and recovery efficiency.
• Reservoir heterogeneity (variations in these properties across the reservoir) strongly influences hydrocarbon distribution and production strategy.

Geochemical analysis techniques

Multiple analytical methods are used together to characterize petroleum composition, determine its origin, and reconstruct its migration history.

Gas chromatography

Gas chromatography (GC) separates complex hydrocarbon mixtures based on compound volatility and polarity as they pass through a column.

• A flame ionization detector (FID) is the standard detector for hydrocarbon analysis
• Whole-oil GC produces a chromatographic "fingerprint" of a crude oil, useful for comparing samples
• High-temperature GC extends the analyzable range to heavier compounds
• Two-dimensional GC (GC×GC) uses two columns with different selectivities, dramatically improving separation of complex mixtures

Mass spectrometry

Mass spectrometry (MS) identifies compounds based on their mass-to-charge ratio ($m/z$).

• GC-MS couples chromatographic separation with mass spectral identification, and is the workhorse technique for biomarker analysis
• Selected ion monitoring (SIM) mode enhances sensitivity for target compound classes (e.g., monitoring $m/z$ 191 for hopanes, $m/z$ 217 for steranes)
• Tandem MS (MS/MS) provides structural information on complex molecules
• FT-ICR MS (Fourier transform ion cyclotron resonance) achieves ultra-high mass resolution, enabling precise molecular formula assignment for thousands of compounds simultaneously

Isotope ratio analysis

Stable isotope ratios provide information about source organic matter and thermal history.

• Carbon isotope ratios ($\delta^{13}C$) help distinguish marine vs. terrestrial organic matter sources and track maturation
• Hydrogen isotope ratios ($\delta D$) reflect source water composition and maturation processes
• Compound-specific isotope analysis (CSIA) measures isotope ratios of individual molecules using GC-IRMS (gas chromatography-isotope ratio mass spectrometry)
• Clumped isotope analysis measures the abundance of bonds between two heavy isotopes (e.g., $^{13}C$–$^{18}O$), offering constraints on formation temperatures independent of source fluid composition

Petroleum system elements

The petroleum system concept integrates all geological elements and processes required for a hydrocarbon accumulation to exist: source rock, reservoir, seal, trap, and the processes of generation, migration, and accumulation. All must be present and properly timed.

Source rock evaluation

Rock-Eval pyrolysis is the standard screening tool for source rock quality:

1. The sample is heated in an inert atmosphere.
2. The S1 peak measures free (already generated) hydrocarbons released at low temperature.
3. The S2 peak measures hydrocarbons generated by cracking kerogen at higher temperature, representing remaining generation potential.
4. $T_{max}$ (the temperature at the S2 peak) indicates thermal maturity.

From these measurements:

• Hydrogen Index ($HI = S2/TOC \times 100$) and Oxygen Index ($OI = S3/TOC \times 100$) help classify kerogen type on a modified Van Krevelen diagram
• TOC analysis quantifies total organic matter content
• Microscopic examination of kerogen (visual kerogen analysis) identifies organic matter types directly
• Biomarker analysis of source rock extracts enables correlation with crude oils found in reservoirs

Timing and maturation

The timing of hydrocarbon generation relative to trap formation is critical. If hydrocarbons are generated before the trap exists, they'll migrate through and be lost.

• Burial history modeling reconstructs the thermal evolution of source rocks through time
• The time-temperature index (TTI) estimates cumulative thermal exposure
• Vitrinite reflectance provides a direct, measured maturity indicator
• Biomarker maturity parameters (e.g., sterane isomerization ratios, hopane isomerization ratios) independently assess oil maturity
• Integrating multiple maturity indicators reduces ambiguity in maturity assessments

Migration pathways

• Fluid inclusion analysis traps tiny samples of ancient fluids in mineral crystals, providing direct evidence of paleo-fluid migration
• Oil-source rock correlation (matching biomarker and isotopic signatures) helps reconstruct which source rock charged which reservoir
• Lateral migration follows high-permeability carrier beds; vertical migration exploits faults and fractures
• Surface geochemical anomalies in soils and sediments can indicate active hydrocarbon seepage from depth
• Basin modeling integrates geological and geochemical data to simulate migration in 1D, 2D, or 3D

Environmental considerations

Petroleum geochemistry techniques are directly applicable to environmental problems, from identifying pollution sources to monitoring cleanup efforts.

Oil spill fingerprinting

When oil is spilled, identifying its source requires detailed chemical comparison:

• Biomarker ratios are particularly useful because they resist weathering better than lighter compounds
• GC-MS provides detailed chemical fingerprints of spilled vs. candidate source oils
• Diagnostic ratios of specific compounds (e.g., hopane and sterane ratios) help differentiate between oil sources
• Weathering (evaporation, dissolution, photo-oxidation) alters oil composition over time, so fingerprinting must account for these changes
• Stable isotope analysis adds another dimension for source discrimination
• Statistical methods like principal component analysis (PCA) and hierarchical clustering handle the large datasets involved in oil-oil and oil-source correlations

Biodegradation of petroleum

Microorganisms preferentially attack certain compound classes in a well-established sequence:

1. n-Alkanes are degraded first (their absence on a GC trace is a classic indicator of biodegradation)
2. Branched alkanes (isoprenoids) go next
3. Cyclic and aromatic compounds are progressively attacked
4. Hopanes and steranes are among the most resistant compounds

Biodegradation indices based on compound ratios quantify the degree of alteration. In deep reservoirs, anaerobic biodegradation can severely degrade oil quality, increasing viscosity and sulfur content. Biomarker analysis helps distinguish biodegradation from other alteration processes like water washing or thermal cracking.

Remediation techniques

• Bioremediation: Uses microorganisms to break down petroleum contaminants. Can be enhanced by adding nutrients or oxygen.
• Phytoremediation: Employs plants to extract, stabilize, or degrade pollutants in contaminated soils.
• Chemical oxidation: Rapidly degrades petroleum hydrocarbons using strong oxidants (e.g., permanganate, persulfate, Fenton's reagent).
• Soil vapor extraction (SVE): Removes volatile organic compounds from the unsaturated (vadose) zone by applying vacuum.
• Monitored natural attenuation (MNA): Relies on natural physical, chemical, and biological processes to reduce contaminant concentrations over time. Requires ongoing geochemical monitoring to verify effectiveness.

Exploration applications

Petroleum geochemistry data, integrated with geological and geophysical information, directly supports exploration decisions and risk assessment.

Basin modeling

Basin models simulate the entire evolution of a sedimentary basin and its petroleum systems:

• 1D models reconstruct burial and thermal history at a single well location
• 2D models capture lateral variations along a cross-section
• 3D models simulate the full spatial complexity of basin properties, migration, and accumulation
• Models incorporate thermal history, source rock properties (TOC, kerogen type), and migration physics
• Calibration against measured data (vitrinite reflectance, bottom-hole temperatures, biomarker maturity parameters) is essential for model reliability
• Sensitivity analysis tests how uncertainties in input parameters (e.g., heat flow, erosion estimates) affect predicted outcomes

Prospect risk assessment

Geochemical data help evaluate the probability that each petroleum system element is present and effective:

• Has a viable source rock been identified? Is it thermally mature?
• Do oil-source rock correlations confirm that the source has generated and expelled hydrocarbons?
• Do fluid inclusions in reservoir or carrier rocks provide evidence of paleo-hydrocarbon migration?
• Does surface seepage analysis indicate active generation and migration?
• Probabilistic methods integrate geochemical uncertainties with structural and stratigraphic risk factors to produce overall prospect risk estimates

Reserve estimation methods

• Volumetric methods use geochemical data to constrain hydrocarbon yields from source rocks
• Material balance calculations incorporate PVT (pressure-volume-temperature) properties derived from fluid analysis
• Decline curve analysis benefits from understanding how fluid composition changes over a field's production life
• Analog field comparisons rely on geochemical similarities between fields for resource estimation
• Reservoir simulation models incorporate fluid property data from geochemical characterization
• Uncertainty quantification in reserve estimates accounts for geochemical variability across the reservoir

Production geochemistry

During field development and production, geochemical techniques help optimize recovery and manage reservoir behavior.

Fluid characterization

• GC analysis characterizes light hydrocarbon distributions in produced fluids
• High-temperature simulated distillation determines boiling point distributions, which feed into refinery planning
• Asphaltene stability analysis predicts whether asphaltenes will precipitate and cause flow assurance problems (plugging wells or pipelines)
• Trace metal analysis informs corrosion risk assessment for production equipment
• Isotope analysis of produced water identifies fluid sources and detects mixing between zones

Reservoir compartmentalization

Reservoirs that appear continuous on seismic data may actually contain internal flow barriers. Geochemistry can detect these:

• Different oil compositions in adjacent wells suggest compartmentalization (the oils haven't been able to mix)
• Vertical and lateral compositional gradients that are steeper than expected from gravity segregation alone point to barriers
• Integration of geochemical data with pressure data and production behavior strengthens compartmentalization interpretations
• Time-lapse geochemistry tracks changes in produced fluid composition over time, revealing how different compartments contribute to production
• Molecular diffusion modeling helps distinguish physical barriers from compositional gradients caused by slow diffusion

Production allocation techniques

When multiple reservoir zones or wells produce into a common facility, geochemistry can determine each zone's contribution:

• Multivariate statistical analysis of produced fluid compositions identifies distinct fluid populations
• Stable isotope ratios serve as natural tracers for commingled production
• Gas composition and isotope ratios (e.g., $\delta^{13}C$ of methane, ethane, propane) allocate gas production to specific zones
• Integration with production logging and well test data improves allocation accuracy
• Monitoring of natural or artificial tracer compounds tracks inter-well communication

Unconventional resources

Unconventional reservoirs require different geochemical approaches because the source rock, reservoir, and sometimes the seal are the same formation, or because the hydrocarbons have unusual physical properties.

Shale oil and gas

In shale plays, organic-rich shales function as both source and reservoir:

• TOC content is critical for assessing resource potential
• Thermal maturity indicators ($\%R_o$, $T_{max}$) determine whether the shale is in the oil window, wet gas window, or dry gas window
• Kerogen type influences both the volume and type of hydrocarbons generated
• Gas storage occurs both as free gas in pore space and as adsorbed gas on organic matter and clay surfaces. Adsorption capacity directly affects producible gas volumes.
• Geomechanical properties (brittleness, fracability) are influenced by organic matter content and thermal maturity, linking geochemistry to completion design

Oil sands and heavy oil

Heavy oil and bitumen are high-viscosity hydrocarbons typically found in unconsolidated sands or carbonates:

• Biodegradation is the most common process responsible for heavy oil formation, as microbes preferentially remove lighter compounds
• High asphaltene and resin content drives up viscosity and complicates recovery
• Elevated sulfur and metal (V, Ni) content creates processing and environmental challenges
• Steam-assisted gravity drainage (SAGD) is a major thermal recovery method; geochemical insights help optimize steam-oil ratios and predict fluid behavior
• In-situ upgrading techniques aim to crack heavy molecules downhole, reducing viscosity before production

Coalbed methane

Coalbed methane (CBM) is natural gas stored within coal seams:

• Gas can be thermogenic (generated by thermal maturation of coal) or biogenic (produced by microbial activity), and many coals contain a mixture
• Gas content and composition vary with coal rank (a measure of thermal maturity) and depth
• Adsorption isotherms (Langmuir isotherms) characterize how much gas the coal can hold at a given pressure
• Desorption studies on core samples measure how quickly gas releases as pressure drops, informing production forecasts
• Produced water chemistry analysis is important for both production forecasting and managing environmental impacts of water disposal

Future trends

Petroleum geochemistry is evolving beyond traditional oil and gas applications, with techniques increasingly applied to energy transition challenges.

Enhanced oil recovery

• Chemical EOR methods (polymer, surfactant, alkaline flooding) use geochemical insights to optimize fluid-rock interactions
• Smart water flooding tailors injection water ionic composition based on geochemical analysis of reservoir mineralogy and fluid chemistry
• $CO_2$ EOR requires understanding of miscibility conditions and fluid-rock interactions to maximize oil displacement
• Microbial EOR leverages geochemical knowledge to stimulate beneficial microbial activity in reservoirs
• Real-time geochemical monitoring enables adaptive EOR strategies during injection

Carbon capture and storage

• Geochemical characterization of potential storage reservoirs assesses containment capacity and long-term integrity
• Fluid-rock interaction studies predict how injected $CO_2$ will react with reservoir minerals and formation water over decades to centuries
• Geochemical tracers (both natural and injected) track $CO_2$ movement in the subsurface
• Mineral trapping ($CO_2$ reacting with silicate minerals to form stable carbonates) provides the most permanent form of sequestration
• Risk assessment incorporates geochemical factors such as potential leakage pathways and seal reactivity

Renewable energy integration

Petroleum geochemistry expertise is finding new applications:

• Geothermal energy exploration uses many of the same fluid geochemistry and reservoir characterization techniques
• Rare earth element extraction from produced waters could support clean energy technologies
• Subsurface hydrogen storage in depleted reservoirs or salt caverns applies petroleum system concepts (trap, seal, reservoir)
• Lithium brine exploration uses geochemical analysis of formation waters to identify economically viable lithium concentrations
• Repurposing existing oil and gas infrastructure for energy storage and distribution leverages decades of subsurface geochemical knowledge