Kinetic modelling of petroleum formation and cracking: implications from the high pressure/high temperature Elgin Field (UK, North Sea)

Retardation of oil cracking to gas and pressure induced combination reactions to account for viscous oil in deep petroleum basins: Evidence from oil and n-hexadecane pyrolysis at water pressures up to 900 bar

“…Moreover, much of the bitumen previously described as the pyrobitumenic residue after oil cracking has possibly been incorrectly identified. Indeed characterisation of the supposed 'pyrobitumens' in the high temperature (190 °C) high pressure North Sea Upper Jurassic Fulmar Formation (Scotchman et al, 2006) have shown that the 'pyrobitumens' are degraded residues of normal oil window mature North Sea oils, e.g., deasphaltation (Wilhelms and Larter, 1995), and have not formed by oil cracking as proposed by Vandenbroucke et al (1999). In this case may be the high temperatures are preventing the exothermic combination reactions, whereas the high pressures are preventing the endothermic cracking reactions.…”

HPHT reservoir evolution: a case study from Jade and Judy fields, Central Graben, UK North Sea

“…Activation energies were varied between 55 kcal/mol (lowest Ea from Dieckmann et al, 1998) and 70 kcal/mol (highest significant Ea from Schenk et al 1997). For comparison, activation energies for secondary cracking ranged between 54.5 and 68.2 in Vandenbroucke et al (1999). Using the activation energy distribution shown in Table 1, the GOR -saturation pressure trend of natural fluids from the study area (Figure 6), was reproduced satisfactorily.…”

“…These latter kinetic models describe the primary generation of individual components or component classes and their secondary transformations upon increasing thermal stress. While bulk kinetics and compositional predictions from primary cracking have proven their applicability (Schenk, et al, 1997, Schenk andHorsfield, 1993), demonstrating the correctness of secondary cracking predictions has been problematic (Vandenbroucke, et al, 1999). For example the stability of liquid petroleum in reservoirs seems to be relatively high (Horsfield, et al, 1992, Schenk, et al, 1997, indicating that it can withstand temperatures close to 200°C under geologic heating rates, whereas in source rocks residual oil is converted to gas at lower levels of thermal stress (Dieckmann, et al, 1998).…”

“…For example the stability of liquid petroleum in reservoirs seems to be relatively high (Horsfield, et al, 1992, Schenk, et al, 1997, indicating that it can withstand temperatures close to 200°C under geologic heating rates, whereas in source rocks residual oil is converted to gas at lower levels of thermal stress (Dieckmann, et al, 1998). As stated above, compositional predictions from kinetic models in combination with basin models have as yet large difficulties in correctly predicting the fluid composition and phase in deep, hot reservoirs (Vandenbroucke, et al, 1999), although newer models calibrated to observed fluid properties indicate that good predictions regarding the gas to oil ratio (GOR) and even phase properties are possible for the realm of primary cracking (di Horsfield, 2006, di Primio and.…”

Modeling hydrocarbon generation potentials of Eocene source rocks in the Agbada Formation, Northern Delta Depobelt, Niger Delta Basin, Nigeria

“…The total organic carbon and the hydrogen index for the source rock unit were obtained from the Rock-Eval results. The hydrocarbon generation stages were calculated using reaction kinetics data based on Vandenbroucke et al (1999). The models were simulated and calibrated before generating 1-D models.…”