Elsevier

Organic Geochemistry

Volume 39, Issue 8, August 2008, Pages 1150-1161
Organic Geochemistry

Oil–source rock correlations – Limitations and recommendations

https://doi.org/10.1016/j.orggeochem.2008.02.001Get rights and content

Abstract

A rigorous, defensible and causal oil–source rock correlation definitively ties an individual source rock sample to an individual crude oil using genetically-based, internally consistent parameter matches. Such a correlation is a relationship established between the two components which is consistent with all known chemical, geochemical and geological information, and meets three criteria: (a) the relationship must be causal – the oil must arise (at least in part) from the specified source rock(s); (b) chemical data used in the correlation must be comparable – the elemental, molecular and isotopic data derived from the source rock must be of the same type as that derived from the oil; and (c) all available geological data must be supportive – clear geological evidence must exist which allows the proposed source rock to have sourced the oil. The three points of this definition are satisfied, and the correlation is successful, if we solve one analytical and three geological problems. Natural extraction of crude oil from its source rock – i.e., “expulsion” – differs mechanically and temporally from laboratory extraction, leading to a correlation problem referred to as “extraction differences”, and representing the single greatest analytical uncertainty in correlation efforts. Geologically, three aspects confound oil–source correlations: occurrence of multiple source units and/or source units at differing maturity levels; lateral and vertical depositional variations in source unit(s) organic matter; and lateral and vertical variation in-reservoir unit(s) organic matter.

These concerns are overcome by taking five actions for each oil–source correlation effort. (1) Select representative samples using statistically defensible methods. (2) Establish the inherent compositional variability – laterally and temporally – due to depositional and maturation processes in each prospective source unit. (3) Assess the extent of migration-induced changes in oil composition, including post-migration changes such as in-reservoir alteration. (4) Support each correlation with migration histories derived from 4d models. (5) Iterate correlation results with new data gathered from ongoing exploration efforts. These five actions will (a) allow correlation success to be measured more objectively, (b) establish risking parameters for direct use in basin assessment, and (c) provide baseline criteria for use in assessing the reliability of oil–source rock correlations.

Although these approaches will improve conventional oil–source rock correlation efforts, ultimately they may not be needed if inversion methods become more reliable. The ability to invert compositional data for crude oil – i.e., predict the age, lithology, maturity, and other characteristics of a source rock solely through chemical analysis of its expelled oil – could eventually result in successful oil–source rock “correlations” in which source rock analysis for oil–source rock correlation purposes is less critical.

Introduction

Correlation of a crude oil to one or more source rocks is a common industrial application of petroleum geochemistry. Confirmation that oil has been generated in the target sedimentary basin is the most critical piece of knowledge a petroleum explorationist can derive; second in importance is the determination of the source(s) of that oil. For this reason, an extensive arsenal of analytical methods is utilized to collect primary data on the organic matter in crude oils and possible source rocks, and various components of these data are used to relate oils causally to their prospective sources. Oil–source rock correlations at various confidence levels have been established for the petroleum systems of all major sedimentary basins.

Published case studies establishing causal correlations between oil and source rock pairs began to appear in the third quarter of the 20th century (e.g., Hunt et al., 1954, Welte, 1965, Dow, 1974, Williams, 1974) and summaries of oil–source rock correlation studies and methods are now available (Curiale, 1993, Curiale, 1994a, Waples and Curiale, 1999). Although correlations are fundamentally subjective exercises, the results are rarely challenged either conceptually or on their merits. Numerous published examples correlating one or two oil samples to one or two source rocks purport to establish relationships which are commonly carried basinwide. Other examples utilize a decidedly limited suite of geochemical analytical types and data, often establishing strong chemical correlations but no convincing causality. Still others attempt to enforce a chemical correlation on sample sets whose geologic circumstances make such a correlation quite unlikely.

Concerns of this type have been expressed since oil–source correlations were first attempted, although often only as passing remarks in published literature and industry reports. Interestingly, although these concerns have been duly noted by various authors, most of these authors proceeded with their correlation efforts anyway, without any serious effort to address the noted concerns. This has led to unnecessary uncertainty in published results, and the impression that any correlation is better than no correlation. My objectives here are to gather into a single publication the reasons for the subjectivity of oil–source correlations and to recommend conceptual and practical improvements for the use of these correlations in solving industrial problems. In addition, I present some criteria for judging the success of practical oil–source rock correlations, in the hope that these criteria will assist in defining the risk associated with the charge component of exploration efforts in both frontier and mature basins.

Any successful oil–source rock correlation must include three attributes: (a) requirement of causality; (b) comparable chemical data for all samples; and (c) geological support. For the purposes of this paper, I will use the definition of Curiale (1993), derived from previous authors and cited in that publication as: an oil–source rock correlation is a causal relationship, established between a crude oil and an oil-prone petroleum source rock, which is consistent with all known chemical, geochemical and geological information. The three key points of this definition are listed below.

  • The relationship must be causal. That is, the oil must arise (at least in part) from the specified source rock.

  • Chemical data used in the correlation must be comparable. That is, the elemental, molecular and isotopic data derived from the source rock must be of the same type as that derived from the oil.

  • All available geological data must be supportive. That is, clear geological evidence must exist which allows the proposed source rock to have sourced the oil.

The absence of any of these three key points necessarily negates the validity of a proposed oil–source rock correlation. That is: the presence of all three points is required, at a minimum, before declaring a correlation to be successful.

The importance of both the chemical and geological character of these three definitional points cannot be overemphasized. Establishing chemical similarities between the organic matter in a source rock and that in an oil, even if these similarities involve ‘genetic’ (i.e., source-derived) molecular and isotopic characteristics, is necessary but insufficient. Such a result must also be supplemented by supporting geological data establishing that the source was capable – in all spatial and temporal dimensions – of having generated a specific oil. These geological data, including the details of depositional history and structural configuration through time, are provided as input to a robust basin model which is used to support the correlation conclusion in the spatial (i.e., fluid flow configuration) and temporal (i.e., timing of generation and expulsion) dimensions. Only when this is confirmed can a bona fide oil–source rock correlation be concluded with confidence.

Several published, successful oil–source rock correlations have appeared since the first was presented by John Hunt and colleagues over 50 years ago. Hunt et al. (1954) provided clear chemical and geological evidence in a causal framework for the source of oils and solid bitumens of the Uinta Basin (USA). Two decades passed before publication of the seminal work by Williams (1974) and Dow (1974) on the Williston Basin (USA), in which elemental, isotopic and molecular data were used in successful correlations among three source rocks and oil families. Although later studies became progressively more analytically sophisticated, the concepts established by Hunt, Williams and Dow, from which the definition given above was derived, still dominate oil–source rock correlation approaches.

All analytical methods used by petroleum geochemists to characterize oils and the organic matter in source rocks have also been used to correlate oils to source rocks, and the confidence we have in oil–source correlations parallels the confidence we have in petroleum geochemical methods in general. Indeed, the ease and rapidity with which precise analytical data can now be obtained has tended to de-emphasize the importance of geological data, because the precision of chemical data tends to be far greater than that of geological data. In part, this is because rapid temporal changes in the depositional conditions of many sedimentary systems make it difficult to sample these systems representatively. Thus, the fundamental non-analytical obstacle to successful oil–source rock correlations is the natural variability of the geological system, and much of this paper focuses on coping with this variability when attempting oil–source rock correlations.

Our knowledge of variability within depositional systems at all scales has not kept pace with our ability to generate highly precise analytical data. Indeed, chemical correlations are now easy to establish – almost automatic when using some statistical approaches – whereas knowledge of natural, fine-scale variation in source rock deposition (e.g., Curiale, 1994b, Keller and Macquaker, 2001, Barker et al., 2001) is substantially more difficult to acquire. Therefore, although a few aspects of analytical uncertainty remain (mostly based on the type of rock extraction method used – see below), the success of an oil–source rock correlation depends largely on our understanding of sedimentary organic variability in the natural setting.

This problem – making certain that the natural variability of depositional processes is fully considered when establishing oil–source rock correlations – requires that lateral and vertical differences in organic matter distribution in both source and reservoir rocks are accounted for properly. This variability extends from organic differences in source shales at the laminae scale to the potential for multiple source units to drain toward a single focal point (trap). The remainder of this paper discusses these factors using examples. Individual sections briefly address correlation problems arising from the occurrence of extraction technique differences, multiple source units, lateral/vertical source organic variability and lateral/vertical reservoir organic variability. A closing section proposes recommendations for more accurate and consistent correlations, in an effort to minimize the uncertainty in oil–source correlations. In this manner, more accurate correlations can be used in an industrial context, thus reducing exploration risk.

Section snippets

Extraction differences

Most correlation techniques in common use involve molecular and isotopic comparison of components in crude oil with components extracted from a candidate source rock. Natural extraction of crude oil from its source rock – usually denoted as “expulsion” – differs chemically, mechanically and temporally from laboratory extraction, leading to a correlation problem referred to here as “extraction difference”. Laboratory extraction usually utilizes an organic solvent at its boiling point, occurs

Mixing from multiple source units and multiple maturity levels

Increasing use among petroleum geologists and geochemists of thermal and flow modeling at the basin scale has resulted in an increased awareness of the occurrence and importance of multiple source rock units in a sedimentary basin, and the post-source mixing of oil expelled from these units en route to the trap. In addition, maturity-induced compositional variations in crude oil and in the soluble organic matter remaining in a source rock after explusion can be significant, and efforts to

Lateral and vertical organic variability in source deposition

Inspection of modern depositional settings indicates that organic matter accumulation in fine-grained sediments can show extensive compositional variability, both laterally and temporally (Tyson, 1995). As modern sediments become part of the lithified stratigraphic section, this variability is often preserved as compositional variations at the bulk (organic petrographic) and molecular levels. Lithologically homogenous sections often show molecular differences over relatively small vertical

Organic variability in carrier bed and reservoir rock

Although organic facies variations in oil-prone source units provide a first-order control on the composition of expelled oil, so-called non-genetic or post-sourcing events can also change an oil’s composition. In-trap biodegradation, for example, results in several well-recognized compositional changes in crude oil (Larter et al., 2006, and references therein) which, if unrecognized, can result in a failed oil–source correlation effort. Less well-recognized compositional changes that often go

Recommended approach

The previous sections have provided examples of four situations where oil–source rock correlations can be compromised: where laboratory rock extraction techniques differ dramatically from natural oil expulsion; where multiple source units and maturity levels occur in the basin, resulting in oil mixing within the fetch area; where lateral and temporal organic variability within a source unit (i.e., organic facies difference) is substantial; and where migration-induced compositional changes in an

Parting comment – oil–source rock correlations using only oil

Traditional oil–source rock correlations, as discussed throughout this paper, establish compositional and geological comparisons between oil samples and rock samples. However, increased understanding of petroleum systems and, in particular, detailed knowledge of the molecular and isotopic composition of crude oils and the organic matter in their source rocks has led to a non-traditional approach to oil–source rock correlation which I will refer to here as the inversion approach.

Inversion

Acknowledgements

Numerous Unocal and Chevron co-workers have provided ideas and correlation examples which have affected my thinking about oil–source rock correlations, and their help and advice are appreciated. My thanks go to both of these organizations for providing the regional petroleum systems overviews and extensive databases and analytical capabilities necessary to evaluate petroleum source rocks and their associated oils and gases in detail, and for providing approval to present and publish this work.

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