Tertiary and Cretaceous Source Rocks, Gulf of Mexico

Amoco’s 1993 MC-84 well (King) located in the deep-water Gulf of Mexico penetrated both Tertiary and Cretaceous source rocks. This well was drilled in Mississippi Canyon Block 84 and is one of the most basinward penetrations in this GOM locale (Wagner, Sofer, and Claxton, 1994).

A plot of the remaining hydrocarbon generation potential (in this case, close to the original potential) versus the organic carbon content suggests that these are oil prone to mixed oil/gas prone source rocks (Jones, 1984).

Kerogen type based on organic carbon contents and hydrocarbon generation potentials.

Figure 1. Kerogen type based on organic carbon contents and hydrocarbon generation potentials.

Based on Tmax values, measured vitrinite reflectance values, and the sterane isomerization ratios, these samples are of low maturity (immature to early oil window). However, based on the normalized oil contents, the oil contents are higher than expected for these levels of maturity (Figure 2). The values exceeding 100 mg oil/g TOC are lean intervals above Cretaceous source rocks and are likely stained from migrated hydrocarbons from these Cretaceous source rocks.

Wagner et al. (1994) report that the Upper Cretaceous and Lowermost Cretaceous samples are 90%+ amorphous organic matter whereas the Tertiary source rock intervals contain mixed amorphous and structured organic matter although the 14,810 ft. Tertiary sample contains 90% amorphous organic matter.

Biomarker analysis of oil samples recovered at 10, 974 ft. and 11, 184 ft. indicate a common source and show similarity to the organic rich Cretaceous rocks (Wagner et al., 1994).

Based on a combination of geological, geochemical, and basin modeling data, Wagner et al. (1994) suggest that the Lower Cretaceous is the likely source of the discovered oils as the Upper Cretaceous is too thin off-structure to the north of the King well and a migration pathway was not available. They also suggest that the Lower Cretaceous entered the oil window about 6 mabp and after reservoir rocks were deposited and simultaneous to salt movement.

Peak pyrolysis temperatures and normalized oil contents

Figure 2. Peak pyrolysis temperatures and normalized oil contents showing high free oil yields at these low maturity levels.

When only organic rich rocks (> 1.00% TOC) are included in this plot and Tertiary and Cretaceous rocks identified separately, it is obvious that there is likely higher level of kerogen conversion in the Tertiary rocks (Figure 3). It is not likely that these rocks are stained from migrated oil based on their low free oil contents and high generation potentials, but this cannot be ascertained in the absence of extracted rock TOC and Rock-Eval data as well as gas chromatographic fingerprints and more detailed evaluation of biomarker results. The terpane and sterane biomarker signatures are very similar, however.

This higher level of conversion of the Tertiary rocks might be indicative of a more labile kerogen that decomposes under lower thermal stress than more refractory (difficult to crack) Type II kerogens.

It would be interesting to know the sulfur contents of the extracts and oils especially the Tertiary oils as well as the dibenzothiophene-to-phenanthrene ratios.

The Cretaceous source rocks could also have lower normalized oil content as a result of expulsion of some hydrocarbons.

Level of conversion by age and richness

Figure 3. Level of conversion by age and richness (all rocks greater than 1.00% TOC). Tertiary potential source rocks have a higher level of apparent conversion based on the higher normalized oil contents (this presumes that the free oil is indigenous).

Oils recovered at 10,974 ft and 11,184 ft show some similarities to the Cretaceous rock extracts in the MC-84 well (Wagner et al., 1994).

References
Wagner, Bruce E., , and Brenda L. Claxton, 1994, Source Rock in Lower Tertiary and Cretaceous Deep-Water Gulf of Mexico, in Transactions of the Gulf Coast Association of Geological Societies, Vol. XLIV.

Jones, R.W.,1984 Comparison of Carbonate and Shale Source Rocks in AAPG Studies in Geology 18, ed. Jim Palacas, pp 163-180.

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