OIL AND BITUMEN FINGERPRINTING IN EXPLORATION

May 7, 1990
Alan R. Daly Chevron Overseas Petroleum Corp. San Ramon, Calif.
Alan R. Daly
Chevron Overseas Petroleum Corp.
San Ramon, Calif.

High-resolution gas chromatography (GC) and gas chromatography/mass spectrometry (GC/MS) of oils and source-rock bitumens can provide explorationists with a wealth of useful information at relatively little cost. The most diagnostic compounds detected by GC and GC/MS are fairly large organic molecules derived with little change from chemicals in living organisms and known collectively as biological markers or biomarkers. The carbon skeletons of some routinely analyzed biomarkers are shown in Fig. 1. Biomarker distributions observed on gas chromatograms and mass fragmentograms are commonly referred to as fingerprints. This review discusses the variety of information provided by biomarker fingerprints and the ways in which it can be used in exploration and production programs.

OIL-OIL AND OIL-SOURCE CORRELATION

In areas with established production oils can be placed into compositionally distinct groups by comparing their biomarker distributions. After allowances are made for within-group variation and possible effects of alteration in the reservoir, the oil groups are usually inferred to be genetically distinct, i.e., they are considered to have separate sources. The number of oil families and their distribution in a given area has a clear impact on exploration strategies because, other factors being equal, an area with multiple sources is more attractive than one with a single source. For example, several oil families with separate sources in the Ordovician, Devonian, Mississippian, and Pennsylvanian occur in the Williston basin and combine to provide a great variety of productive hydrocarbon plays. In contrast, the South Florida basin has a single family of oils sourced within the Lower Cretaceous, and the variety of hydrocarbon plays is much more limited.

Biomarker fingerprints obtained on source-rock bitumens provide definitive correlations between potential sources and individual oil families. Oil-source correlations combined with source rock information allow migration distances and directions to be deduced, and the results can then be utilized as shown by the next example. Oil-source correlations indicate that three oil families occur in Cambrian-Lower Ordovician carbonates of south-central Oklahoma. The oils originated in younger source beds (Ordovician, Devonian-Mississippian, and Pennsylvanian) and must have migrated along faults in order to move structurally upwards but stratigraphically downwards (Fig. 2). This information allows those exploring the Cambro-Ordovician to critically examine the structural and stratigraphic configurations in the vicinity of their prospects prior to drilling.

OIL CHARACTERIZATION

Biomarker fingerprinting of oils can provide information about the age and depositional environment of their source rocks. These data are particularly useful when, as is often the case, mature source rocks are unavailable for direct correlation with the oils. For example, it has been shown that oils sourced by Middle Ordovician strata can usually be identified on the basis of their very distinctive gas chromatograms (Fig. 3). In a typical basin evaluation program, detection of Middle Ordovician oil would immediately narrow the search for source rock depocenters and suitable migration conduits. Of more general applicability, the recent discovery that sterane fingerprints of oils are related to the geological age of their sources holds promise for dating oils of all ages.

Recognition of biomarkers derived from particular types of organisms can be helpful in certain situations, especially when the organisms have a limited time range or are restricted to particular depositional environments. For instance, contributions from certain conifers to source rocks and oils can be detected via GC/MS of their terpene distributions. The presence of conifer-derived terpenes in oils indicates a Permian or younger age for their source because the conifers in point first became abundant in the Permian. Similarly, the occurrence of oleananes (terpenes derived from flowering plants) in oils indicates a Large Cretaceous or younger age. Furthermore, an abundance of any of the terpenes discussed is indicative of a terrestrial or marginal-marine source facies.

When combined with geological information biomarker fingerprints of oils can suggest completely new plays. A recent North African discovery provides a good example. Oil with strong terrestrial-plant affinities was encountered in a Tertiary-Cretaceous marine section which to that point had produced only marine oils. The terrestrial character of the new oil together with indirect geological evidence suggested that a terrestrially-dominated source was present beneath the Cretaceous and, therefore, that the pre-Cretaceous section should be prospective. A decision to drill the deeper sections was made largely on the basis of the biomarker data and was rewarded by the discovery of several Jurassic oil accumulations.

Biomarker fingerprinting of oil seeps from undrilled or lightly explored areas is generally very enlightening, and an opportunity to fingerprint a seep should not be turned down. While surface biodegradation generally limits or prevents characterization of seeps by GC analysis, GC/MS is effective in all but the most severe cases.

THERMAL MATURITY MEASUREMENT

Numerous GC/MS parameters are available to measure and directly compare the thermal maturity of oil seeps, reservoired oils, and source rocks. It is particularly important to establish the thermal maturity level of oil seeps with low API gravities because such seeps can arise in very different manners; some represent immature, relatively immobile products that have not migrated very far from their sources while others are mature but biodegraded and indicate hydrocarbon generation and possible accumulation at depth. Fig. 4 is a cross-plot of two sterane maturity parameters measured on oil seeps and potential source rocks from a South American basin. The plot shows that the seeps have maturity levels typical of normal oils, and that some of the correlative source rocks (sampled in outcrop) are sufficiently mature to have generated the oils.

The maturity level of reservoired oils can have a significant impact on exploration evaluations as is illustrated by the following example from Central America. Analysis of cuttings revealed that oil staining was very common in immature sections of the study area which appeared to lack good source intervals. Two possible origins for the oil were considered; (a) local generation in small amounts and at low maturity levels, or (b) generation in deeper, more mature areas followed by long-range, updip migration. The first origin was clearly demonstrated by the presence of immature sterane and terpene distributions in the stains, and that finding strongly influenced later exploration strategies in the region.

Biomarker maturity parameters have been used to estimate and compare the paleo heat flows of various basins (Mackenzie et al, 1981). A cross-plot of two GC/MS parameters measured on rock bitumens is employed (Fig. 5). In the example shown low heat flows were operative during basin subsidence. Heat flow information obtained in this manner can be used to help constrain the subsurface temperature values used in mathematical models of oil generation.

DEVELOPMENT GEOLOGY

Geologists used detailed GC fingerprinting of oils to answer a variety of economically important questions related to productive reservoirs. The data were used to determine reservoir continuity, estimate contributions from separate reservoirs when production was commingled, and identify production problems. The technique has been applied during both the early and late stages of field development, and its used represents an important extension of biomarker application. Fig. 6 shows a typical reservoir continuity problem that, depending on reservoir characteristics and well spacing, may be time consuming and costly to answer using conventional engineering techniques; however, the two situations shown can often be rapidly discriminated by analyzing oils from both wells and comparing their fingerprints.

SUMMARY

When combined with geological information biomarker fingerprinting of oils and bitumens is a powerful and cost-efficient method for addressing several types of exploration questions. The data obtained help to reveal the exploration potential of poorly explored basins and they may suggest previously unconsidered plays in basins with established production. Recent work suggests that detailed fingerprinting of oils has the potential to be of great value in development geology.

Author has references.

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