Sedimentary basins are physical and chemical reactors with a multitude of interacting processes, chiefly controlled by temperature and pressure conditions. We integrate the analysis of temperature, pressure and other rock physical data and model the evolution of pore pressure conditions in ultra-tight organic mudrocks in Eastern Arabia. We observe a nonlinear behavior of pressure and thermal maturation, representing a particular challenge for the prediction of pore pressure away from well control.

Arabian lithosphere exhibits variations in its thermal structure imposing significant variations on the regional heat flow distribution and on the fate or organic matter in hydrocarbon source rocks. Highest heat flow is observed in deep sedimentary troughs having evolved since the Late Proterozoic as intracontinental sag basins. Modeling revealed that the thermal maturity pattern is a direct consequence of heat flow distribution and regional subsidence, themselves controlling rock properties like total porosity and secondary kerogen porosity.

Kerogen has been entirely converted to solid bitumen and generated hydrocarbon fluids represent a spectrum from black oil to dry condensate gas. Rock bulk density gradually decreases as a function of increasing kerogen conversion to solid bitumen as petroleum precursor, from where liquid and vapor hydrocarbons form and expel as a mobile phase.

Observing pore pressure from production wells reveals an increase during early maturation, followed by pressure dissipation during mid to peak hydrocarbon generation, and renewed pressure build up during the late maturation window. We attribute the episodic, nonlinear pore-pressure behavior to the conversion process of organic matter within the ultra-tight mudrocks, followed by volume expansion, swelling, fracturing, and expulsion. Fracture healing, evident from core observation sets mechanical rock conditions up for renewed pressurization as long as heating and maturation continues. Modeling over-pressure along geological time reveals the high pressures persist within the host rocks for prolonged geologic periods due to their low permeability and consequently restricted fluid mobilization.

Applying numerical Basin Modeling techniques enabled to unravel the time-relationship between the individual processes and to generate pore pressure maps away from well control. Generated over-pressures persist over long geological time scales, being favored by the low system permeability. Pressure associated with hydrocarbon generation and volume expansion makes up to 20% of the total observed pore pressure in the system.

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