Using Oil Biomarkers in Petroleum Exploration
Biomarkers are a group of compounds, primarily hydrocarbons, found in oils, rock extracts, Recent sediment extracts, and soil extracts.
What distinguishes biomarkers from other compounds in oil is that biomarkers can reasonably be called "molecular fossils". Biomarkers are structurally similar to, and are diagenetic alteration products of, specific natural products (compounds produced by living organisms).
Typically, biomarkers retain all or most of the original carbon skeleton of the original natural product, and this structural similarity is what leads to the term "molecular fossils".
Biomarkers have a variety of applications in petroleum exploration. For example:
- When samples of oil and candidate source rocks are available, biomarkers can be used to make oil-source rock correlations, or
- When samples of candidate source rocks are NOT available, the biomarker distribution in an oil can be used to infer characteristics of the source rock that generated the oil WITHOUT examining the source rock itself. Specifically, biomarkers in an oil can reveal (1) the relative amount of oil-prone vs. gas-prone organic matter in the source kerogen, (2) the age of the source rock, (3) the environment of deposition as marine, lacustrine, fluvio-deltaic or hypersaline, (4) the lithology of the source rock (carbonate vs. shale), and (5) the thermal maturity of the source rock during generation (e.g., Peters and Moldowan, 1993). Such data may be key inputs to effective basin modeling of a prospect or block.
Petroleum Biomarkers Indicative of Source Rock Organic Matter Input and Depositional Conditions (Table 1)
Below are a few examples of oil biomarker parameters that provide information about the depositional environment of the source rock and the origin of the organic matter in the source rock.
|Source Information||Biomarker Parameter||Comments|
|Marine Source Rock||24-n-propylcholestanes||Ubiquitous in oils derived from marine source rocks. (Moldowan et al., 1990)|
|C42-46 Cyclopentylalkanes with odd/even carbon preference||(Carlson et al. 1993; Hsieh and Philp, 2001)|
|Lacustrine Source Rock||Botryococcane||Presence = lacustrine source. Absence = meaningless. (e.g., Moldowan et al., 1980, Metzger and Laegeau 1999)|
|b-Carotane||Presence = lacustrine source. Absence = meaningless. (Hall and Douglas, 1983; Jiang and Fowler, 1986)|
|Sterane/Hopanes||Low in oils derived from lacustrine source rocks. (Moldowan et al., 1985)|
|C26/C25 tricyclic terpanes||> 1 in many lacustrine-shale-sourced oils. (Zumberge, 1987)|
|Tetracyclic Polyprenoids||High in oils from lacustrine sources. (Holba et al., 2000)|
|C42-46 Cyclopentylalkanes with even/odd carbon preference or with no preference||(Carlson et al. 1993; Hsieh and Philp, 2001)|
|Higher plant input to Source Rock||Oleananes, Lupanes, Taraxeranes||Biomarkers indicating flowering plant input to source. (e.g., Ekweozor and Udo, 1988)|
|Bicadinanes||Derived from Dipterocarpaceae tree resins. (Cox et al., 1986)|
|Retene, Cadalene||Biomarkers indicating conifer input to source. (Noble et al., 1985)|
|Tetracyclic diterpanes||Biomarkers indicating conifer input to source. (Noble et al., 1985)|
|C29 steranes||High relative to total C27-C29 steranes. (Huang and Meinschein, 1979; Moldowan et al., 1985)|
|Coal Source Rock||Pristane/phytane||Very high in coal-sourced oils; e.g., > 3.0 (Hughes et al., 1995)|
|C31 homohopanes||High relative to total C31-C35 in some coal-sourced oils|
|Hypersaline Depositional Environment||Gammacerane||High relative to C31 hopanes in oils derived from sources deposited under hypersaline depositional conditions. High values indicate stratified water column during source deposition. (Sinninghe Damste et al., 1995)|
|Pristane/phytane||Very low values (e.g., < 0.5) in oils derived from source rocks deposited under hypersaline conditions (due to contribution of phytane from halophilic bacteria). (ten Haven et al., 1987; 1988)|
|Anoxic Depositional Environment of Source Rock||C35 homohopanes||High relative to total hopanes in oils derived from source rocks deposited under anoxic conditions (Peters and Moldowan, 1991). Abundance of C35 homohopanes in oils (Relative to C31-C34 homohopanes) is correlated with source rock Hydrogen Index (Dahl et al., 1994).|
|Pristane/phytane||1.0 can indicate anoxic conditions, but the ratio is affected by many other factors.|
|Isorenieratane & related compounds (2,3,6 and 2,3,4 - Trimethylaryl isoprenoids), Chlorobacteria||Presence in oil indicates anoxic photic zone during source rock deposition, since these compounds are biomarkers for green sulfur bacteria. (Summons and Powell, 1987; Grice et al., 1998; Koopmans et al., 1996)|
|V/(V+Ni) Porphyrins||High = reducing conditions. (Lewan, 1984)|
|28,30-bisnorhopane||High in certain reducing environments. (Schoell et al., 1992; Moldowan et al., 1984)|
|Carbonate Source Rock||30-norhopanes||High in carbonate-sourced oils; e.g., C29/C30 hopanes ~ 1 (Fan Pu et al., 1987; ten Haven et al., 1988; Subroto et al., 1991)|
|Diasteranes/steranes||Low in carbonate-sourced oils. (Rubinstein et al., 1975; Hughes, 1984)|
|Dibenzothiophene/phenanthrene||> 1.0 in oils derived from high-sulfur carbonates. (Hughes et al., 1995)|
|2a-methylhopanes||High in carbonate derived oils (Summons et al., 1999)|
|Age of Source Rock Deposition||Oleanane||Present in oils derived from Late Cretaceous or younger sources (Moldowan et al., 1994)|
|(24-norcholestanes)/(26-norcholestanes)||High in many Tertiary sources. Low values are not age-diagnostic. (Holba et al., 1998A; 1998B)|
|Dinosteranes, triaromatic dinosteroids||Absence always means Pre-Mesozoic, while presence USUALLY means Mesozoic or younger. (Moldowan et al., 1996)|
|C29 Monoaromatic Steroids||High in oils derived from sources older than 350 mybp. (Moldowan et al., 1985)|
|C11-C19 Paraffins||Odd-carbon-number predominance in oil from many Ordovician sources. (Douglas et al., 1991; Fowler, 1992)|
High in oils from pre-Ordovician sources. (McCaffrey et al., 1994B)
To characterize charge risk, these biomarker parameters can be used in a variety of innovative ways. For example, specific biomarker parameters can be calibrated against specific kerogen quality parameters in a given basin. Then, the biomarker ratios are measured in an oil sample from the basin, and the values are projected onto calibration curves to quantitatively predict characteristics of the source rock. This approach, pioneered by the founders of OilTracers, allows explorationists to assess whether an oil was generated primarily from an oil-prone or gas-prone organic facies (Dahl et al., 1994; McCaffrey et al., 1994). The information gained from oil biomarkers (source type, age, maturity, kerogen quality) when integrated into a basin model has substantial economic impact because it provides early estimates of oil quantity and GOR for exploration targets in the area of interest.
Using Biomarkers in Oil to Assess Source Thermal Maturity
The relative abundances of certain biomarkers in petroleum change as a function of source rock maturity. As a result, a variety of biomarker parameters have been identified that are very useful for characterizing the source rock maturity simply from analysis of the migrated oil (e.g., Peters and Moldowan, 1993).
Biomarker maturity parameters (e.g., parameters such as those in Table 2) make use of several processes that occur during source rock maturation:
- Cracking--large molecules break into smaller molecules
- Isomerization--changes in the 3-dimentional arrangements of atoms in molecules.
- Aromatization--formation of aromatic rings (loss of hydrogen from naphthenes)
Petroleum Biomarkers Indicative of Source Rock Maturity (Table 2)
|Petroleum Fraction (Compound Class)||Biomarker Parameter Measured in Petroleum Fraction||Effect of Increasing Maturity||Comments|
|Saturated Hydrocarbons||C29 Steranes [20S/(20S+20R)]||Increase||Useful in early to mid oil window. Decreases at very high maturity levels.|
|C29 Steranes [abb/(abb+aaa)]||Increase||Useful in early to mid oil window.|
|Moretane/Hopane||Decrease||Useful in early oil window.|
|C31 Hopane [22S/(22S+22R)]||Increase||Useful in immature rocks to onset of early oil window.|
|Ts/(Ts+Tm)||Increase||Also influenced by source lithology.|
|Tricyclic Terpanes/Hopanes||Increase||Useful in late oil window; also increases at high levels of biodegradation.|
|Diasteranes/Steranes||Increase||Useful in late oil window; also affected by source lithology (low in carbonates, high in shales); also increases at high levels of biodegradation.|
|Aromatic Hydrocarbons||Monoaromatic Steroids: (C21+C22)/ [C21+C22+C27+C28+C29]||Increase||Useful in early to late oil window; resistant to effects of biodegradation.|
|Triaromatic Steroids: (C20+C21)/ [C20+C21+C26+C27+C28]||Increase||Useful in early to late oil window; resistant to effects of biodegradation.|
|Triaromatic /(Monoaromatic + Triaromatic Steroids)||Increase||
Useful in early to late oil window; resistant to effects of biodegradation.
Several considerations must be kept in mind when using petroleum biomarkers to assess source rock thermal maturity. For example:
- The exact relationship between a biomarker parameter and the source maturity is a function of heating rate, source lithofacies, and source organic facies (kerogen type). As a result, the exact maturity (i.e., vitrinite reflectance equivalent) associated with a given value for a biomarker parameter can change from basin to basin. Furthermore, the relationship between a biomarker maturity indicator and source rock maturity is generally non-linear.
- With increasing maturity, many biomarker maturity indicators reach terminal values; hence, a given biomarker parameter is applicable only over a specific maturity range.
- The concentrations of biomarkers in petroleum decrease with thermal maturity.
Despite these limitations, biomarker indicators of source maturity can be extremely useful. For example, biomarker maturity parameters can be used to determine what the API gravity of a biodegraded oil was prior to biodegradation. This is accomplished by collecting a suite of non-degraded oils from the same petroleum system as the degraded oils. Using the non-degraded oils, the geochemist develops a correlation or "transform" between a biomarker maturity parameter and API gravity. The same biomarker parameter is then measured on a degraded oil, and the original gravity is determined using the transform developed from the non-degraded oil suite. Moldowan, et al. (1992) provide an excellent example of this approach in which they determine the original gravity of degraded Adriatic oils. For this application, the most effective biomarker parameters are those based on compounds that are highly resistant to biodegradation, such as [Triaromatic/(Monaromatic +Triaromatic steroids)].
Source Rock descriptions and source rock maturity information derived from oil biomarkers are often key input data for basin modeling of a prospect or block.
Biomarkers in Petroleum are analyzed by gas chromatography mass spectrometry (GC-MS) or gas chromatography - tandem mass spectrometry (GC-MS-MS). Analyses are typically performed on the saturated hydrocarbon fraction or the aromatic hydrocarbon fractions. The oil fractions are prepared by liquid chromatography.
For more information on the techniques described here, or to discuss a specific project, e-mail us at email@example.com, or call us at U.S. (214) 584-9169
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