Devleena Mani

Organic Properties and Hydrocarbon Generation Potential of Shales from Few Sedimentary Basins of India

Shales form the principal source rock for most of the conventional and unconventional petroleum systems. In India, both the prolific and prospective sedimentary basins have excellent to fair development of shales that range in age from the Proterozoic to Cenozoic. Deposition, preservation and maturation of organic content in shales define the source rock characteristics and its hydrocarbon generation potential, leading to a prolific/non prolific oil and gas play. Useful insight on development and hydrocarbon generation potential of shales and other organic rich source rocks is obtained through the geochemical study of sedimentary organic matter. In the present work, organic richness, kerogen type and thermal maturity of potential shales from few sedimentary basin of India, namely—Vindhyan, Krishna-Godavari, Kutch, Cambay and Jammu and Kashmir have been studied, to understand their effectiveness as source rocks in the particular basins. The studied shales show high Total organic carbon (TOC) content and contain dominantly Type III kerogen with partial contributions from Type II, in varying stages of hydrocarbon generation from immature to post mature, depending upon the thermal history of respective basins. Quantitative approaches involving the use of kinetic parameters for thermal cracking of organic matter (kerogen) into hydrocarbons, in conjunction with the source rock quality can account for improved understanding of the hydrocarbon resources in these basins.

Pyrolysis results of shales from the South Cambay basin, India: Implications for gas generation potential

Shale, an abundant organic-rich sedimentary rock of extremely low porosity, is of lately being realized as a significant energy source, owing to the possibility of huge amount of natural gas which may be stored in it. Instigated by the enormous production of natural gas from the shale formations of Barnett, Marcellus and several other plays in USA, the Indian sedimentary basins are being looked assertively for their shale gas prospects. The petroliferous Cambay basin in western India with interbedded carbonaceous shales in its thick Tertiary sequence forms a potential prospect for the shale gas. Fine grained, clastic and organic-rich Cambay, Tarapur and other Tertiary shales have sourced the oil and gas for the basin.The quality, quantity and type of organic matter play an important role in the generation of gas in shale horizons. Rock-Eval pyrolysis is one of the most basic organic geochemical methods to study these parameters. In the present study, the interbedded shale formations within the middle Eocene lignite sequences, referred to as Cambay Formation, (Nagori et al., 2013), of the Tadkeshwar and Rajpardi mines in Surat and Bharuch districts, respectively, have been sampled to study the organic matter properties using Rock-Eval pyrolysis. The sedimentary sequences exposed in the mines show the shales to be high in Total Organic Carbon (TOC) content, ranging between 0.2% to 47.3%. The S1 (free hydrocarbons) and S2 (hydrocarbons from cracking of kerogen) values range between 0.04 to 7.12 and 0.08 to 190.11 mg HC/g rock, respectively. The Tmax (temperature at highest yield of S2) varies between 342°C to 450°C, and the hydrogen index (HI) ranges between 32 to 754 mg HC/ g TOC. The variation of HI vs. Tmax suggests an immature to mature stage for the hydrocarbons. The organic matter in shales is characterized by Type II / III kerogen, suitable for the generation of gas.

Hydrocarbon source potential of the Proterozoic Sirban Limestone Formation, NW Himalaya, Jammu

The Proterozoic Sirban Limestone Formation (SLFm) crops out as detached allochthons in the northwest Himalaya (Jammu region, India) and has its coeval equivalents laterally disposed in the west in Salt Range, in the northwest in Abbotabad (Pakistan) and in southeast in Himachal Pradesh (India). The oil and gas occurrences have been reported from the Proterozoic successions globally and the hydrocarbon potential of the SLFm cannot be ruled out.The interbedded shales and algal laminated dolostones within the SLFm have yielded microflora comparable to those reported in the North African Neoproterozoic sandstones and the Late Proterozoic carbonates of the giant oil and gas fields of the Siberian Platform. The SLFm contains a rich and diverse biota comprising ~ 10% of the rock volume in thin section. The rich organic assemblage justified a hydrocarbon source potential analysis of the SLFm, tested in this study by Rock Eval (RE) pyrolysis.RE pyrolysis yielded a total organic carbon (TOC) content of 0.02 to 1 wt. % with very low Hydrogen Index (HI) values for the shales and TOC content averaging 0.02 wt. % for the dolostones. The organically lean shales and dolostones exhibit Tmax values indicative of immature to post mature stage. But, since these values are for the samples with complex thermal and tectonic history the results may be unreliable. The highly altered organic matter and kerogen present in the SLFm had the potential to generate hydrocarbons and presently indicates no significant source potential. This study is important for understanding the hydrocarbon occurrences in the SLFm particularly in light of the recent oil and gas discoveries from the coeval Proterozoic successions.

Geochemical characterization of adsorbed light gaseous alkanes in near surface soils of the eastern Ganga basin for hydrocarbon prospecting

This study aims to assess the hydrocarbon potential of Ganga basin utilizing the near surface geochemical prospecting techniques. It is based on the concept that the light gaseous hydrocarbons from the oil and gas reservoirs reach the surface through micro seepage, gets adsorbed to soil matrix and leave their signatures in soils and sediments, which can be quantified. The study showed an increased occurrence of methane (C1), ethane (C2) and propane (C3) in the soil samples. The concentrations of light gaseous hydrocarbons determined by Gas Chromatograph ranged (in ppb) as follows, C1: 0–519, C2: 0–7 and C3: 0–2. The carbon isotopic (VPDB) values of methane varied between −52.2 to −27.1‰, indicating thermogenic origin of the desorbed hydrocarbons. High concentrations of hydrocarbon were found to be characteristic of the Muzaffarpur region and the Gandak depression in the basin, signifying the migration of light hydrocarbon gases from subsurface to the surface and the area’s potential for hydrocarbon resources.