Organic geochemical characteristics of source rocks and crude oils in the North Malay basin, Malaysia-Thailand joint development area (JDA) / Siti Hanisah Sidik - Siti Hanisah , Sidik (2023)
The study is conducted in the acreage of Malaysia-Thailand Joint Development Area (MTJDA), within the matured and prolific North Malay Basin, at the southern part of the Gulf of Thailand with an aerial coverage of about 7250 km2 and water depth ranging between 45 m and 60 m. Exploration in MTJDA has started in 1970’s with many gas fields have been developed and producing gas since 2000’s. Most of the hydrocarbons produced were accumulated in the structural or structural-stratigraphy traps within the shallow levels of late Miocene post-rift sequences. In Malay basin, the oil accumulation has been considered to have been generated mainly from Group K, L and M lacustrine source rock while the organic-rich bearing strata of Group E are considered still immature for hydrocarbon generation due to shallow burial depth. In view of the lacustrine source rock, the MTJDA is expected to have accumulated significant amount of oil, however this area is a gas prone basin. The deltaic coal/ shale in Group E is presumed to be possibly the main effective source rock that generated mainly gas in the JDA. In this research, the geochemical characteristics of the syn-rift and the post-rift source rock and oil/ condensate samples were evaluated. The objectives are to study the organic matter characteristics, thermal maturity level of source rock, distinguish the biomarkers of crude oil and source rocks, and to understand the relationship of hydrocarbon by oil-oil and oil-source correlation. The geochemical analysis reveals that the rock cutting sediments generally were moderate in quality with variable richness based on TOC (total organic carbon), and variable degree of maturity based on the biomarkers analyses of isoprenoid, hopanoid and steroid. From the geochemical analyses, the crude samples in this area are originated from the coaly and carbonaceous shales of Group I, with mixed kerogen of type II/III that capable to produce gas with minor oil. There’s also a possibility that these hydrocarbons were originated from a lower Group E interval (better maturity) which was deposited in a similar setting as Group I. However, most of the extracts of Group E showed a lower degree of maturity, thus lowering the possibility that the hydrocarbon originated from this interval.