Crude oil geochemical analysis decodes the molecular and isotopic composition of petroleum to reveal its source, thermal maturity, migration history, and post-accumulation alteration. Accredited third-party laboratories apply advanced chromatographic and mass spectrometric techniques to support oil-source correlation, reservoir evaluation, and production optimization throughout the upstream petroleum industry. This article provides a comprehensive technical overview of crude oil geochemical analysis, covering sample types, testing items, analytical methods, and practical applications.
Technical Overview
Crude oil geochemical analysis is the systematic application of organic and analytical chemistry to petroleum samples in order to reconstruct their genetic and thermal history. Because crude oil inherits a molecular fingerprint from the organic matter of its source rock, detailed compositional analysis allows geochemists to identify the type of organic matter (marine, lacustrine, or terrigenous), the thermal maturity at which the oil was generated and expelled, the extent of secondary alteration such as biodegradation or water washing, and the degree of mixing between multiple migration and charging events.
The discipline rests on three complementary information carriers. Bulk properties and SARA composition describe the gross physical and chemical character of the oil. Biomarker compounds, such as steranes, terpanes, and aromatic steroids, retain skeletal structures inherited from precursor organisms and serve as genetic markers resistant to secondary processes. Stable isotope ratios of carbon and hydrogen record source and process information at both the bulk and compound-specific level. When these datasets are integrated, they provide the scientific foundation for oil-oil correlation, oil-source rock correlation, petroleum system analysis, and reservoir geochemistry studies.
Testing Samples
Wellhead, Separator, and Stock Tank Crude Oil
Representative crude oil samples collected at the wellhead, separator, or storage tank constitute the primary sample type. A volume of 10 to 50 mL is generally sufficient for a complete analytical suite. Proper sampling protocols, including the use of clean glass or fluoropolymer containers and the avoidance of plastic contact, are essential to prevent contamination of the light hydrocarbon and biomarker fractions.
Condensates and Volatile Oils
High-maturity fluids generated from overmature source rocks or condensates associated with gas accumulations contain low concentrations of conventional biomarkers. Their evaluation emphasizes light hydrocarbon distributions (C5-C7), diamondoid concentrations, and gas chromatographic fingerprints, often supplemented by carbon isotope analysis of individual n-alkanes.
Reservoir Rock Extracts from Cores and Cuttings
Organic matter extracted from reservoir cores and drill cuttings via Soxhlet extraction or pressurized fluid extraction provides movable and residual oil signatures. These extracts are invaluable for identifying pay zones, assessing reservoir continuity, and characterizing paleo-oil accumulations, provided that contamination from oil-based drilling mud is identified and corrected using drilling fluid reference samples.
Oil Seeps, Shows, and Bitumen Samples
Surface and subsurface oil seeps, stained cuttings, solid bitumens, and asphaltic residues from frontier basins are analyzed to establish the presence of a working petroleum system. Despite advanced biodegradation or weathering, resistant biomarkers and asphaltene-bound geochemical information can frequently still be recovered from such samples.
Testing Items
A comprehensive geochemical evaluation typically integrates the following categories of testing, tailored to the geological question being addressed.
Bulk Properties and Fluid Characterization
- API gravity and density
- Sulfur and nitrogen content
- Viscosity, pour point, and wax content
- Total acid number and water and sediment content
SARA Fractionation
Quantification of saturates, aromatics, resins, and asphaltenes defines the gross compositional framework of the oil and constrains source type, maturity, and biodegradation level. Asphaltene isolation with n-heptane follows established procedures consistent with IP 143 and ASTM D6560, while full fractionation is performed by column chromatography consistent with ASTM D2007 or equivalent validated laboratory procedures.
Saturated Hydrocarbon Analysis
- n-Alkane and isoprenoid distribution (C8-C40)
- Carbon preference index (CPI) and odd-even predominance
- Pristane/phytane ratio and pristine/n-C17 versus phytane/n-C18 cross-plots
- Acyclic isoprenoid ratios for redox and source facies interpretation
Biomarker Analysis
- Terpanes and hopanes (m/z 191): Ts/Tm ratio, homohopane distribution, moretane/hopane ratio
- Steranes (m/z 217-218): regular and rearranged sterane distributions, C27-C28-C29 ternary classification
- Age-diagnostic markers such as oleanane (angiosperm input, Cretaceous or younger) and dinosteranes
- Diasterane/regular sterane ratios for clay-rich versus carbonate source facies
- Aromatic steroids for high-maturity correlation
Aromatic Hydrocarbons and Molecular Maturity Parameters
- Methylphenanthrene index (MPI-1) and methylphenanthrene distribution fraction
- Methyldibenzothiophene ratio (MDR) for carbonate versus clastic source indication
- Triaromatic sterane and monoaromatic sterane ratios
- Vitrinite-equivalent reflectance estimated from molecular maturity transformations
Stable Isotope Analysis
- Bulk carbon isotope composition of whole oil and of SARA fractions
- Hydrogen isotope composition of saturated and aromatic fractions
- Compound-specific isotope analysis (CSIA) of n-alkanes and isoprenoids by GC-C-IRMS
Light Hydrocarbons and Diamondoids
- C5-C7 light hydrocarbon star diagrams for correlation and maturity (Thompson parameters such as heptane and isoheptane values)
- Mango paraffinicity and K1 ratio for correlation
- Diamondoid concentrations (adamantane, diamantane series) as high-maturity and cracking indicators
Testing Methods
Sample Preparation and Fractionation
Crude oil is deasphaltened with n-heptane, and the maltene fraction is separated into saturates, aromatics, and resins by liquid chromatography over silica-alumina columns. Quality control employs certified reference materials, duplicate analyses, surrogate internal standards such as deuterated n-alkanes and steranes, and blank corrections. National and industry standards of the GB/T and SY/T series govern sampling and fractionation procedures where applicable.
Gas Chromatography with Flame Ionization Detection (GC-FID)
Whole-oil and saturated-fraction GC-FID provides the n-alkane and isoprenoid distribution, unresolved complex mixture (UCM) baseline indicative of biodegradation, wax content estimation, and carbon number range. Standardized procedures align with the simulated distillation framework of ASTM D2887 and the extended boiling range distribution of crude oils described in ASTM D7169.
Gas Chromatography-Mass Spectrometry (GC-MS and GC-MS/MS)
GC-MS in selected ion monitoring (SIM) mode quantifies biomarker ratios on the saturated and aromatic fractions. Tandem GC-MS/MS in multiple reaction monitoring (MRM) mode offers enhanced selectivity and sensitivity for target compounds in biodegraded or low-concentration samples, resolving coeluting sterane and terpane isomers that SIM cannot separate.
Isotope Ratio Mass Spectrometry (IRMS and GC-C-IRMS)
Elemental analyzer IRMS determines bulk carbon isotope ratios of whole oil and isolated fractions, while gas chromatography-combustion-IRMS yields compound-specific carbon isotope signatures of individual hydrocarbons. These data are reported against the VPDB standard and are powerful tools for correlating oils lacking distinctive biomarkers.
Supporting Standardized Physical and Chemical Tests
- ASTM D4052 or ASTM D1298 for density and API gravity
- ASTM D445 for kinematic viscosity and ASTM D5853 for pour point of crude oils
- ASTM D4294 for sulfur by energy-dispersive X-ray fluorescence
- ASTM D664 for total acid number and ASTM D5762 for nitrogen
- ASTM D3230 for chloride salts and ASTM D4006 or ASTM D4928 for water content
- IP 143 and ASTM D6560 for asphaltene precipitation
Applications
- Oil-oil correlation and classification of petroleum families within a basin
- Oil-source rock correlation to confirm the effective source kitchen
- Thermal maturity assessment and calibration of basin and petroleum system models
- Reservoir continuity and compartmentalization studies based on compositional comparison of produced oils
- Production allocation and monitoring of commingled or sequentially produced zones
- Assessment of biodegradation, water washing, and thermochemical sulfate alteration on fluid quality
- Source identification for oil spills, pipeline contamination, and environmental forensics disputes
- Screening of crude quality parameters relevant to refinery feedstock valuation and custody transfer
- Support for enhanced oil recovery programs through fingerprint tracking of injected and produced fluids
FAQ
How much crude oil is required for a full geochemical analysis?
A volume of 10 to 50 mL of liquid sample is typically sufficient for the complete suite, including SARA fractionation, GC-FID, GC-MS biomarkers, and isotope analysis. Rock samples generally require 50 to 200 g of core or cuttings, depending on total organic carbon and oil saturation.
How long does crude oil geochemical analysis take?
Routine analyses such as GC-FID and SARA fractionation are usually completed within five to ten working days. Full biomarker and compound-specific isotope programs, including quality review and interpretation, typically require ten to twenty working days depending on sample count.
Can heavily biodegraded oils still provide meaningful geochemical data?
Yes. Although n-alkanes and light hydrocarbons are consumed during biodegradation, steranes, hopanes, and aromatic steroids are highly resistant and remain diagnostic. In extreme cases, GC-MS/MS analysis of 25-norhopanes or isotope analysis of asphaltenes can be applied to recover source and correlation information.
Can geochemistry indicate the age of the source rock?
Certain biomarkers offer age constraints. Oleanane indicates angiosperm-rich, Cretaceous or younger source rocks, while specific dinosterane distributions suggest Mesozoic to Cenozoic marine sources. Age assignments are interpretive and must be combined with regional geological evidence.
How is drilling fluid contamination handled in rock extract analysis?
Reference samples of the oil-based mud and additives are analyzed in parallel with the rock extracts. Contaminant chromatographic peaks are stripped, mathematical decontamination is applied where possible, and biomarkers absent from the mud system are preferentially used for interpretation.
What quality assurance is applied in accredited third-party laboratories?
Accredited third-party laboratories operate under ISO/IEC 17025 management systems, employing certified reference materials, internal standards, procedural blanks, duplicate analyses, and interlaboratory calibration programs to ensure the accuracy and comparability of geochemical datasets.