D.J. Patil

Glacial-interglacial changes in the surface water characteristics of the Andaman Sea: Evidence from stable isotopic ratios of planktonic foraminifera

Stable carbon and oxygen isotopic analyses of the planktonic foraminifera (Globigerinoides ruber) from a deep sea sediment core (GC-1) in the Andaman Sea show high glacial-to-Holocene δ18O amplitude of 2.1%o which is consistent with previously published records from this marginal basin and suggest increased salinity and/or decreased temperature in the glacial surface waters of this region. A pulse of18O enrichment during the last deglaciation can be attributed to a Younger Dryas cooling event and/or to a sudden decrease of fresh water influx from the Irrawady and Salween rivers into the Andaman Sea. High δ13C values observed during the isotopic stages 2 and 4 are probably due to the enhanced productivity during glacial times in the Andaman Sea.

Geochemical assessment of light gaseous hydrocarbons in near-surface soils of Kutch-Saurashtra: Implication for hydrocarbon prospects

Light hydrocarbons in soil have been used as direct indicators in geochemical hydrocarbon exploration, which remains an unconventional path in the petroleum industry. The occurrence of adsorbed soil gases, methane and heavier homologues were recorded in the near-surface soil samples collected from Kutch–Saurashtra, India. Soil gas alkanes were interpreted to be derived from deep-seated hydrocarbon sources and have migrated to the surface through structural discontinuities. The source of hydrocarbons is assessed to be thermogenic and could have been primarily derived from humic organic matter with partial contribution from sapropelic matter. Gas chromatographic analyses of hydrocarbons desorbed from soil samples through acid extraction technique showed the presence of methane through n-butane and the observed concentrations (in ppb) vary from: methane (C1) from 4–291, ethane (C2) from 0–84, propane (C3) from 0–37, i-butane (iC4) from 0–5 and n-butane (nC4) from 0–4. Carbon isotopes measured for methane and ethane by GC-C-IRMS, range between −42.9‰ to −13.3‰ (Pee Dee Belemnite – PDB) and −21.2‰ to −12.4‰ (PDB), respectively. The increased occurrence of hydrocarbons in the areas near Anjar of Kutch and the area south to Rajkot of Saurashtra signifies the area potential for oil and gas.

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.

Geo-microbial prospecting studies of surface sediments from petroliferous region of the Mehsana Block, North Cambay Basin

Surface adsorbed gas surveys and geo-microbiological surveys are well known techniques of petroleum exploration and aim towards risk reduction in exploration by way of identifying the areas warm with hydrocarbons and to establish inter-se exploration priorities amongst the identified warm areas. The thermogenic surface adsorbed gaseous hydrocarbons distribution patterns in petroliferous areas are considered to be a credible evidence for the upward migration of hydrocarbons. The present investigation aims to explore correlation between the adsorbed gas distribution pattern and microbial oxidizers in identifying the upward migration of hydrocarbons especially in the tropical black soil terrain of known petroliferous Mehsana Block of North Cambay Basin, India. A set of 135 sub-soil samples collected, were analyzed for indicator hydrocarbon oxidizing bacteria, adsorbed light gaseous hydrocarbons and carbon isotope ratios (13Cmethane and δ13Cethane). The microbial prospecting studies showed the presence of high bacterial population for methane (5.4 × 106 cfu/gm), ethane (5.5 × 106 cfu/gm), propane (4.6 × 106 cfu/gm) and butane oxidizing bacteria (4.6 × 106 cfu/gm) in soil samples. The light gaseous hydrocarbon analysis showed that the concentration ranges of C1, C2, C3, iC4 and nC4 are 402 ppb, 135 ppb, 70 ppb, 9 ppb and 18 ppb, respectively, and the value of carbon isotope ranges of methane −29.5 to −43.0‰ (V-PDB) and ethane −19.1 to −20.9‰ (V-PDB). The existence of un-altered petroliferous microseep (δ13C, −43‰) of catagenetic origin is observed in the study area. Geo-microbial prospecting method and adsorbed soil gas and carbon isotope studies have shown good correlation with existing oil/gas fields of Mehsana. Microbial surveys can independently precede other geochemical and geophysical surveys to delineate area warm with hydrocarbons, and mapped microbiological anomalies may provide focus for locales of hydrocarbon accumulation in the Mehsana Block of Cambay Basin.

Characterization of organic carbon in black shales of the Kachchh basin, Gujarat, India

Thirty-three black shale samples from four locations on the onland Kachchh basin, western India were analyzed to characterize organic carbon (OC), thermal maturity and to determine the hydrocarbon potential of the basin. Upper Jurassic black shales from the Jhuran Formation (Dhonsa and Kodki areas) are characterized by the presence of chlorite, halloysite, high

Stable Isotope Stratigraphy: Correlations and Implications for Hydrocarbon Microseepage and Prospecting

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Correlation of trace elements with hydrocarbon microseepage

Tmax, low OC, low hydrogen index and high oxygen index. These parameters indicate the OC as type IV kerogen, formed in a marine environment. The rocks attained thermal maturity possibly during Deccan volcanism. Early Eocene samples of the Naredi Formation (Naliya-Narayan Sarovar Road (NNSR) and the Matanomadh areas) are rich in TOC, smectite, chlorite and framboidal pyrite, but have low