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Oil generation (C14+ hydrocarbons) of three Type II kerogen samples isolated from brackish-lacustrine mudstones from Palaeogene strata (Ed3, Es1, Es3) in the southern Bohai Sea was simulated by closed-system gold tube experiments. In addition, a series of complementary analyses (Rock-Eval pyrolysis, total organic carbon, vitrinite reflectance, trace element, X-ray diffraction and flash pyrolysis-gas chromatography–mass spectrometry) were also performed to identify the bulk geochemistry, palaeo-environment and chemical composition of the kerogen. The aim of this study was to achieve a better understanding of the kinetics of oil generation from lacustrine source rocks in the southern Bohai Sea. The results show that the three samples are Type II source rocks deposited in similar palaeo-environments (hot and arid climates, anoxic conditions, and brackish water in shallow to semi-deep lakes) with consequent similarity in the chemical compositions of their kerogens. The organic matter inputs are predominantly composed of lacustrine microalgae, with a relatively small contribution from land plants. The activation energies of oil generation from these samples show a range of 44–52 kcal/mol, with a frequency factor varying from 1.116 × 1014 to 1.274 × 1014 s−1. Due to the similar palaeo-environments and chemical composition, samples in this study exhibit strong consistencies in kinetic parameters. Transformation ratio (TR) evolution curves of oil generation from the three samples, calculated under a linear heating rate (3 K/Ma), exhibit a slight difference, which varies within 4 °C at a given TR. Due to the great similarities of the three kinetic models, an average kinetic model for the Type II brackish-lacustrine source rocks in the southern Bohai Sea was established. This model integrates the characteristics of the three kinetic models and is still dominated by activation energy of 52 kcal/mol. The geological temperature of the oil generation phase for the average model i

Pyrolysis and bulk kinetic studies were used to investigate the hydrocarbon generation potential and source rock organofacies variability of marine organic-rich rocks from the Middle Ordovician (Darriwilian) Goldwyer Formation in the Canning Basin, Western Australia. Rock-Eval pyrolysis results for the analysed immature to mid-mature calcareous mudstones imply that the upper Goldwyer Sequence I contains oil-prone type I kerogen, while the lower Goldwyer Sequence III contains type II/III oil- and gas-prone kerogen. This is supported by pyrolysis gas chromatography (Py-GC) results that show the presence of homogenous organofacies in the Goldwyer Sequence I having aliphatic molecular signatures, possibly due to selective preservation of lipids derived from Gloeocapsomorpha prisca (G. prisca). The heterogeneous organofacies of the Goldwyer Sequence III contain aromatic moieties in similar abundance to the aliphatic compounds. The calcareous claystones of the Goldwyer Sequence I have the capacity to generate low wax paraffinic oil, whereas the Goldwyer Sequence III has potential for paraffinic-naphthenic-aromatic (P-N-A) low wax oils, gas, and condensate. The temperature for hydrocarbon generation for the type I kerogen, assuming a constant geological heating rate of 3 °C/my, is estimated to occur over a narrow interval between 145 °C and 170 °C for the Goldwyer Sequence I samples. Generation from the type II/III kerogen occurs from 100 °C to 160 °C in the Goldwyer Sequence III samples which are significantly less thermally stable than the Goldwyer Sequence I samples. The kinetic results for both sequences were used in standard thermal and burial history plots to evaluate their transformation ratio and hydrocarbon generative potential. This provided basin-specific kinetic inputs for burial history modelling and better constraint on kerogen transformation and hydrocarbon generation on the Broome Platform.

The stratigraphic record along the continental margin of Labrador and Newfoundland provides ample evidence for vertical movements both prior to and after break-up. In the offshore domain, several major hiatuses punctuate the stratigraphic record. Along Labrador and the Grand Banks, Lower Cretaceous rocks rest on Paleozoic rocks or Precambrian basement in parts of the area. Onshore Labrador, the presence of a Cretaceous outlier on Precambrian basement adds to the evidence of one or more events of exhumation that has removed pre-Cretaceous sediments on a regional scale. Over much of the Labrador shelf, Miocene deposits are absent, and we show evidence based on vitrinite reflectance and sonic data that indicate that Miocene deposits of significant thickness may have been present prior to uplift and exhumation. We also present results from a pilot study comprising apatite fission-track analysis (AFTA) data that reveals a Phanerozic history involving a series of burial and exhumation episodes. The pilot study is a forerunner for a study of the onshore and offshore domain with three components. (1) A thermochronological study based on samples from outcrops and from onshore and offshore boreholes. (2) A stratigraphic landform analysis of the onshore study area based on mapping of denudation surfaces that will provide evidence of vertical motion using cross-cutting relationships between the denudation surfaces and stratigraphic constraints. (3) An integrated interpretation of the geological, geomorphological and thermochronological data to provide a coherent model of the timing and magnitude of the vertical movements along the margin both prior to and after break-up. Failure to account for greater depths of burial prior to exhumation may lead to serious underestimation of the petroleum resource maturity and to erroneous estimates of the timing of hydrocarbon generation. Uplift and exhumation may also lead to changes in migration routes and affect hydrocarbons present in res

At the Kuh-e Mond anticline (Fars Province, SW Iran) and in nearby offshore structures,large volumes of natural gas are reservoired in the Permian ? Early Triassic DehramGroup while heavy oil has been discovered in the Cretaceous Sarvak and Eocene JahrumFormations. In this paper, we use data from six exploration wells and from nearby surfaceexposures to reconstruct the burial history at Kuh-e Mond. Regional observations showthat the thick sedimentary fill in this part of the Zagros Basin was subjected to intensetectonism during the Zagros Orogeny, with a paroxysmal phase during the late Mioceneand Pliocene. Thermal modelling and geochemical data from Kuh-e Mond and adjacentfields allows possible hydrocarbon generation and migration mechanisms to be identified.Maturities predicted using Lopatin?s TTI model are in accordance with maturities obtainedfrom vitrinite reflectance measurements.We show that formations which have source potential in the nearby Dezful Embayment(including the Pabdeh, Gurpi, Gadvan and Kazhdumi Formations) have not reached theoil window in the Mond wells. Moreover, their organic carbon content is very low as theywere deposited in oxic, shallow-water settings. Underlying units (including the Ordovicianand Cambrian) could have reached the gas window but contain little organic matter.Silurian shales (Sarchahan Formation), which generate gas at Kuh-e Gahkum andKuh-e Faraghan (north of Bandar Abbas) and in Saudi Arabia and elsewhere in theMiddle East, are absent from the Mond structure.The absence of source rocks suggests that the gas and heavy oil accumulations at Kuh-eMond and at nearby fields have most probably undergone long-distance lateral migrationfrom distant source kitchens.

This study investigates the effect of water pressure on hydrocarbon generation and source rock maturation at high maturities for a perhydrous Tertiary Arctic coal, Svalbard. Using a 25 ml Hastalloy vessel, the coal was pyrolysed under low water pressure (230–300 bar) and high water pressure (500, 700 and 900 bar) conditions between 380 °C and 420 °C for 24 h. At 380 °C and 420 °C, gas yields were not affected by pressure up to 700 bar, but were reduced slightly at 900 bar. At 380 °C, the expelled oil yield was highest at 230 bar, but reduced significantly at 900 bar. At 420 °C cracking of expelled oil to gas was retarded at 700 and 900 bar. As well as direct cracking of the coal, the main source of gas generation at high pressure at both 380 °C and 420 °C is from bitumen trapped in the coal, indicating that this is a key mechanism in high pressure geological basins. Vitrinite reflectance (VR) was reduced by 0.16 %Ro at 380 °C and by 0.27 %Ro at 420 °C at 900 bar compared to the low pressure runs, indicating that source rock maturation will be more retarded at higher maturities in high pressure geological basins.

This study investigates the effect of water pressure on hydrocarbon generation and source rock maturation at high maturities for a perhydrous Tertiary Arctic coal, Svalbard. Using a 25 ml Hastalloy vessel, the coal was pyrolysed under low water pressure (230–300 bar) and high water pressure (500, 700 and 900 bar) conditions between 380 °C and 420 °C for 24 h. At 380 °C and 420 °C, gas yields were not affected by pressure up to 700 bar, but were reduced slightly at 900 bar. At 380 °C, the expelled oil yield was highest at 230 bar, but reduced significantly at 900 bar. At 420 °C cracking of expelled oil to gas was retarded at 700 and 900 bar. As well as direct cracking of the coal, the main source of gas generation at high pressure at both 380 °C and 420 °C is from bitumen trapped in the coal, indicating that this is a key mechanism in high pressure geological basins. Vitrinite reflectance (VR) was reduced by 0.16 %Ro at 380 °C and by 0.27 %Ro at 420 °C at 900 bar compared to the low pressure runs, indicating that source rock maturation will be more retarded at higher maturities in high pressure geological basins.

This study investigates the effect of water pressure on hydrocarbon generation and source rock maturation at high maturities for a perhydrous Tertiary Arctic coal, Svalbard. Using a 25 ml Hastalloy vessel, the coal was pyrolysed under low water pressure (230–300 bar) and high water pressure (500, 700 and 900 bar) conditions between 380 °C and 420 °C for 24 h. At 380 °C and 420 °C, gas yields were not affected by pressure up to 700 bar, but were reduced slightly at 900 bar. At 380 °C, the expelled oil yield was highest at 230 bar, but reduced significantly at 900 bar. At 420 °C cracking of expelled oil to gas was retarded at 700 and 900 bar. As well as direct cracking of the coal, the main source of gas generation at high pressure at both 380 °C and 420 °C is from bitumen trapped in the coal, indicating that this is a key mechanism in high pressure geological basins. Vitrinite reflectance (VR) was reduced by 0.16 %Ro at 380 °C and by 0.27 %Ro at 420 °C at 900 bar compared to the low pressure runs, indicating that source rock maturation will be more retarded at higher maturities in high pressure geological basins.