Abstract Lower Cambrian shale in the Upper Yangtze Platform (UYP), South China, is an important source rock of many conventional petroleum fields and was recently recognized as a promising unconventional shale reservoir. In this paper, hydrocarbon generation kinetics and petroleum physical properties were investigated using the PhaseKinetics approach ( di Primio and Horsfield, 2006 ) and a Cambrian shale sample from the Georgina Basin, North Territory Australia (NTA), as similar paleogeological and sedimentary environments in Cambrian are found for the UYP and NTA. The source rock comprises type II kerogen and belongs to an organofacies generating Paraffinic–Naphthenic–Aromatic low wax oil. Bulk petroleum generation can be described by a single frequency factor A = 8.43E + 14 (1/s) and a dominant activation energy at 56 kcal/mol, which is characteristic for sulphur-poor organic matter deposited in an anoxic marine environment. Onset (transformation ratio TR = 10%) and end (TR = 90%) of bulk hydrocarbon generation was calculated to take place at 120 °C and 165 °C respectively for an assumed average geological heating rate of 1.5°C/Ma. Based on the thermal history of a local “model”-well, onset temperature was not reached until the Middle Triassic (241 ma) when sediments were buried more than 2000 m and basalt eruptions caused enhanced heat flows. The main generation stage of primary petroleum took place during the Middle–Late Triassic and ended in the Early Jurassic (187 ma) for burial depths exceeding 4000 m (TR 90%; 165 °C). Temperatures increased to more than 200 °C in the Middle–Late Jurassic leading to secondary cracking of primary products. Hydrocarbons formed at the onset (TR = 10%) of petroleum generation can be characterized by a gas-oil-ratio (GOR) of 63 Sm3/Sm3, a saturation pressure (Psat) of 101 bar, and a formation volume factor (Bo) of 1.2 m3/Sm3. Those parameters stay low during primary petroleum generation before 203 ma, at temperatures > 10,000 Sm3/Sm3, Psat > 250 bar and Bo > 2.0 m3/Sm3) during secondary cracking starting roughly at 200 ma, 152 °C and 3500 m burial. Assuming zero expulsion, the shale reservoir position within the sedimentary basin indicates that bubble point pressure was always below reservoir pressure, and fluids in the shale reservoir occurred only as a single, undersaturated phase throughout maturation history. Black oil and volatile oil phases dominated during the primary cracking period, whereas wet gas and dry gas phases dominated during the secondary cracking period.