Productivity control on oil shale formation—Mae Sot Basin, Thailand

Abstract

Neogene oil shales from the freshwater, lacustrine, intermontane Mae Sot Basin, western Thailand, are examined in order to define (a) oil source rock potential, (b) variations in molecular and isotopic geochemical characteristics, and (c) the influence on source potential of organic matter productivity and preservation. Twelve samples spanning 7 m of section were examined using conventional isotopic, molecular, and organic petrographic methods of geochemical analysis; temporal resolution is 2700 yr per sample. Because thermal maturity differences and fluid migration within the sample set are absent, and organic matter type input variation is either minor or absent (based on visual kerogen analysis), we propose that organic matter differences among the samples are caused by variability in surface-water productivity. All samples are excellent potential source rocks ( VR = 0.4−0.5% R o) containing Types I and II organic matter (modified van Krevelen plot determination) consisting of almost 100% fluorescent amorphous kerogen (visual kerogen determination). Numerous diagnostic molecular markers and characteristics are present, including perhydro-β-carotene, dammaranes, norsterane(s), and novel distributions of tricyclic terpanes. Stable carbon isotope ratios of kerogens and extract fractions range over 5%, and co-vary with hydrogen index. This covariance is attributed to temporal increases in surface-water productivity leading to CO 2-limiting conditions and consequent increase in δ 13C of the organic matter in the photic zone. During times of elevated productivity, increased amounts of 13C-enriched organic matter reached the water-sediment interface. Thus times of greater productivity are accompanied by higher δ 13C and hydrogen index values, with δ 13C related to productivity under CO 2-limiting conditions, and HI related to the relative amount of the water column that was anoxic during deposition. Our findings suggest that, in petroleum geochemical studies involving lacustrine source rocks, δ 13C values must be used with caution as oil-oil and oil-source rock correlation parameters.