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Intra-Delta Versus Sub-Delta Sourcing of Petroleum - a Global Review*
By
Olukayode J. Samuel1, D. Martin Jones1, and Chris Cornford2
Search and Discovery Article #40243 (2007)
Posted June 25, 2007
*Adapted from extended abstract prepared for 2006 AAPG International Conference and Exhibition; November 5-8, 2006; Perth, Australia
1School of Civil Engineering and Geosciences, Drummond Building, University of Newcastle upon Tyne, NE1 7RU, UK ([email protected])
2Integrated Geochemical Interpretation Ltd (IGI), Hallsannery, Bideford, Devon, EX39 5HE, UK
Petroleum occurrences in sedimentary basins are
routinely described in relation to the source rock from which they have been
generated. This concept of looking at petroleum occurrence in terms of the
physical and temporal processes of generation in and expulsion from a single pod
of mature source rock is termed a “Petroleum System” (Perrodon 1992; Magoon and
Dow 1994a). By various migration pathways, a single Petroleum System may charge
a number of accumulations with reservoirs at various stratigraphic levels and
traps (structures + seals) of various types. By emphasizing the efficiencies of
generation, expulsion, migration and entrapment, the Petroleum System concept
encourages prediction of volumes and composition in undrilled prospects.
Arguably this statement is least true for oil and gas 
exploration
in river-mouth
deltas.
Most of the world’s major deltas with known
hydrocarbon potential are shown in Figure 1. These
include the Beaufort-Mackenzie, Assam-Barail, Niger, Mississippi, Mahakam,
Mekong, Amur, Lema, and Baram. Oil and gas reservoired within deltaic sediments
constitute a significant percentage of the world’s known hydrocarbon reserves,
but whether these accumulations are truly generated from source rocks within the
delta remain unproven. According to Peters et al. (2005, p.752), nearly all the
petroleum systems defined for Tertiary deltas have been assigned the speculative
to hypothetical level of certainty. This may be because, in the thick wedge of
prograding sediments that constitute a delta, organic-rich oil-prone source
rocks are rarely encountered in exploration wells. With the exception of
delta-top coals, typical deltaic sediments are organic lean and not particularly
oil-prone. This leaves three possible models for the sourcing of oil and gas
reservoired within deltaic sediments:
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That intra-delta source rocks exist, but, other than perhydrous coals, have yet to be reliably identified.
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That the relatively lean source rocks encountered can account for the observed volumes of oil and gas, implying exceptionally high expulsion and migration efficiencies.
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That oils are generated in sub-delta source rocks and migrate into deltaic reservoirs.
In order to discriminate between these models, we have studied the geochemistry of 250 reservoired oils at the molecular and isotopic level to reflect the source rock ‘organofacies’ as it reflects the combination of organic matter type and depositional environment ( Jones, 1987; Peters et al., 2000; Haack et al., 2000). This approach of drawing inference of deltaic source rock facies from the basin’s regional petroleum accumulation rests on the assumption that the oil’s composition has been little (or predictably) altered during the sequence of generation in, and expulsion from, the source rock, followed by migration through the carrier beds.
The delta-top sediments of tropical deltas contain shale through to perhydrous coal (e.g., Assam-Barail, Mahakam), with only the latter enriched in oil-prone macerals such as resins, cuticles, pollen, and spores. In contrast, the kerogens of intra-delta shales are generally low in oil-prone amorphous organic matter and hence constitute Type III gas-prone (vitrinitic) kerogen (Durand and Parratte, 1983; Bustin, 1988). A number of workers have carried out individual studies on both source rock characterisation and the crude oil geochemistry in these deltas; e.g., Mackenzie Delta (e.g., Snowdon and Powell, 1979; Curiale, 1991), Assam-Barail Delta (e.g., Raju and Mathur, 1995; Goswami et al; 2005), Mahakam Delta (e.g., Durand and Parratte, 1983; Peters et al., 2000), Niger Delta (e.g., Ekweozor and Okoye, 1980; Bustin, 1988; Haack et al., 2000; Eneogwe and Ekundayo, 2003). Of the studied deltas, oil-source rock correlations are highly disputatious. Arguably, the most reliable correlation is obtained from the Assam-Barail delta, which is the “fringe” Barail Delta partly buried under, and partly exposed as a result of the Naga overthrust (Goswami et al., 2005).
Common to all these studies is that significant proportions of the oils reservoired in the Tertiary sands do not share geochemical affinity with the so-called delta source rock samples. For instance, in the Niger Delta, the source rock is described as a low TOC (average ca. 1.5%) and Type III kerogen-dominated facies (Ekweozor and Okoye, 1980; Bustin, 1988), and it has been proposed that the thick source rock interval compensates for the poor source rock quality (Bustin, 1988; Demaison and Huizinga, 1994). If the huge volume of oil accumulated within the Niger Delta is to be sourced from such analysed Tertiary sediments, very high transformation, expulsion, and migration efficiencies are demanded. Thus, there is a geochemical paradox between the volumes and types of produced oil and Tertiary source rocks. In general, this appears to be a global phenomenon and raises some key questions:
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a) Do deltas act primarily as sedimentary overburden to mature the organic-rich rocks buried below them, and hence as reservoirs to accommodate oils expelled from pre-existing source rocks?
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b) How much of the oil in deltaic accumulations is truly generated by the lean and generally mixed ‘gas+oil-prone’ kerogens seen in deltaic source rocks?
To address this issue (and as a prelude to new analyses of a global collection of Tertiary deltaic oils), in addition to few oils from our own analyses, we have assembled from published literature a large database of bulk, molecular and isotopic properties of analysed oils.
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The C27-C29 sterane ternary diagram (Figure 2) provides useful visual assessment of the organic matter provenance of a large crude oil dataset. The Assam-Barail samples group closely within the regions marked as coaly and delta top source rock facies as described by Goswami et al. (2005) as the coals of the Oligocene Barail Formation and the Kopili shale. The oils from the Mahakam Delta plot nearby as expected for the first major basins where coal has been demonstrated to be volumetrically capable of sourcing commercial oil (Durand and Parratte, 1983). However, in detail samples of oils from the Mahakam discriminate two groups; the first group as seen in Figure 2 is a coaly facies sourced oil, while the second minor group plots in the shallow marine to open marine source environment field. It is interesting to add that the oil plotting in the shallow-open marine area of the graph contains significant quantities of C30 sedimentary n-propyl cholestane (as detected by GCMS/MS), which is associated with marine chrysophyte algae precursor (Moldowan et al., 1990). In addition, these oils contain very little higher plant input as indicated by the Oleanane Index, and this distinction is further corroborated by the stable carbon isotope data plots (Figure 3), where the canonical variable discriminates between marine and terrigenous oils (Figure 4). On the basis of the plotted bulk (isotopes) and molecular (sterane) ratios, nearly all the Niger Delta oils in the dataset are of marine aspect, while conversely the vast majority of the Mahakam delta oils are of terrigenous aspect. These observations provide an initial method of discriminating between oils from within or from beneath the delta. While the Niger Delta oils mainly appear to derive from sub-delta sources, the Assam-Barail and most of the Mahakam oils show characteristics of intra-delta sourcing. The bimodal distribution of the Beaufort-Mackenzie oils imply sourcing from both intra- and sub delta sources: viz., from a coaly and delta top source facies and a marine arguably sub-delta source. These conclusions are supported by less complete data sets for pristane/phytane, sterane/hopane, and oleanane/hopane ratios.
Discussion and Conclusion The molecular and isotopic evidence presented above suggests that oil accumulations within Tertiary deltas (Figure 5) can contain: i. oils of a marine aspect arguably expelled from sub-delta source rocks ii. oils of a more terrigenous aspect expelled from intra-delta source rocks iii. logically, mixes of intra- and sub-delta oils.
We believe that the source rocks for the sub-delta oils are marine shales which have become overstepped by the prograding delta. In the case of the Mackenzie and Niger deltas, these marine shales contain high TOC values and Type II algal-bacterial kerogens. The lateral equivalents of these sub-delta deposits may be seen as low-maturity outcrops on the delta flanks, with examples being the Upper Cretaceous Smoking Hills and Cenomanian-Turonian Nara (lower Benue trough) formations for the Mackenzie and Niger deltas, respectively. The timing of oil generation from the sub-delta source rock is controlled by prograding delta, it being earlier in the proximal and later in the distal locations. Buoyancy- and pressure-driven oil migration fills deltaic reservoirs via a 3-D network of sub-vertical listric fault and sub-horizontal interbeds of mud and sand. It is acknowledged that shales within deltas may be marine in organic character and contain a variable mix of land-derived and planktonic biomass. Typically these shales are lean, due to the combination of oxic depositional conditions and high sedimentation rates. The leanness of the shales is compensated by efficient expulsion, promoted by the intimate interbedding of silt and sand beds. As the locus of deposition moves seaward, the prodelta shales become buried beneath the delta, potentially providing an additional source of ‘marine’ type oil.
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