Abstract

Fewer than 70 exploration wells have been drilled in Bangladesh (207,000 km2), mostly in the eastern onshore and offshore areas, making it one of the least explored countries in the world. Tectonic developments have controlled the accommodation space available for sediment deposition since the Early Cretaceous. Collision between the Indian plate and Eurasia to the north of Bangladesh and between the Indian plate and the Burma platelet on the east provided favorable conditions for development of Oligocene-Miocene source rocks and Miocene reservoir sands in eastern Bangladesh. The resulting Jenam-Bhuban Boka Bil petroleum system is the most active system identified to date and is dominant in eastern Bangladesh. Hydrocarbons likely also have been generated from the organic-rich shales of the Miocene Bhuban formation. The Jenam-Bhuban Boka Bil petroleum system alone is responsible for the generation of more than 16 tcf of gas in place discovered to date, mostly in the Surma basin of the Chittagong-Tripura fold belt. Several other petroleum systems have been postulated in Bangladesh. Together, the best technical estimate of the total resource base is about 61 tcf, including reserves within the discovered fields, anticipated field growth, and new field discoveries.

With the exception of small bacterial contributions in some surface seep gases and two subsurface accumulations, the gases of Bangladesh are thermogenic. Modeling results indicate that the gases and associated condensates are sourced at peak generation depths of at least 6 km. Many of the gas accumulations are associated with retrograde condensates whose compositions are defined by two distinct source facies and by the solution/exsolution effects of vertical migration. Most of the condensates possess molecular signatures that indicate a major hydrogen-rich, angiospermous (flowering land plant) contribution to the organic matter of their source rock(s). The carbon isotope ratios of the methane in the gases and the isotopic and molecular characteristics of the associated condensates indicate a distinct source facies for petroleums of the northern Surma basin relative to those in the south. These isotopic and molecular results, when interpreted in light of the geological framework and our basin models, suggest that the Oligocene Jenam formation is the major contributor north of 24.4 °N and that the Miocene Bhuban formation is the major contributor to the south.

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