Previous pressure-volume calculations during oil cracking to gas, based on the conventional model that presupposes oil cracking to be completed by approximately 150°C, underestimate the potential for gas accumulation in petroleum reservoirs. In this article, a compositional kinetic model of gas generation from oil cracking is suggested based on pyrolysis data using sealed gold tubes, and the pressure-volume changes are recalculated based on the new kinetic model under various geological conditions. The kinetic modeling of oil cracking confirms that crude oil begins cracking at about 160°C for a heating rate of 2°C/m.y., and that the oil-cracking process has two distinct stages with significant differences in gas composition. The first stage is characterized by dominant C2–5 wet gases, whereas the second is characterized by the recracking of C2–5 wet gases to methane and pyrobitumen, leading to a progressive increasing dryness of the gas. The pressure-volume-temperature simulations of oil cracking to gas show that initial oil saturation, temperature-pressure gradients, and openness of reservoirs are important geological factors that control gas accumulation in original petroleum reservoirs. For a reservoir that is geologically open and saturated with 100% oil, gas spills out of the trap at 196°C. The gas loss at 240°C is almost 50% of the total gas, far lower than the 75% based on the conventional model of oil destruction. With lower oil saturation, the gas loss decreases because the gas-water contact can shift downward, and the gas loss occurs mainly by solution. For effectively isolated reservoirs, oil cracking readily exceeds lithostatic pressure, leading to reservoir fracturing, which becomes more obvious when oil saturation decreases. The calculated fracturing temperatures for 100 and 50 vol.% oil saturations correspond to oil destructions of 95% and 86.4%, greatly exceeding the value of 1% as suggested by previous studies. A conceptual model of gas accumulation and loss in isolated and open geological conditions for a reservoir with 50% oil saturation is suggested. On the basis of this model, the Triassic carbonate gas pool in northeastern Sichuan Basin was discussed as a typical example for in-situ accumulation of gas cracked from reservoired oils. The present model infers that the reservoired oils were completely cracked into gas at 87.6 Ma, and that 75–85% of the gas has been preserved in the original reservoir rocks to form the in-situ gas pools with a huge amount of gas resources. We believe that gas accumulation from oil cracking in original petroleum reservoirs is much more prospective than previously thought, and that gas cracked from oil has great potential in other areas of the Sichuan Basin and the eastern Tarim Basin.

A total of 225 rock samples and 37 oil samples from the Beibuwan Basin, South China Sea, were analyzed with geochemical and organic petrological techniques to evaluate the Eocene lacustrine source rocks and investigate controls on their properties and the distribution of different oil families in the basin. Two types of organic facies are recognized in the Liushagang Formation (LS). The first organic facies is algal-dominated and mainly occurs in the organic-rich, laminated mudstones of the middle member of the LS (LS-2) that were deposited in an anoxic, stratified, medium–deep lake environment. It is geochemically identified by its high abundance of C30 4-methylsteranes and heavy δ13C values in the range of −22.4‰ to −27.5‰. The organic matter in this organic facies comprises type I and II1 kerogens, with its macerals dominated by fluorescent amorphous organic matter (AOM) and exinites, indicating a highly oil-prone character. The second organic facies is of terrestrial algal origin and is mainly identified in the nonlaminated mudstones of the upper (LS-1) and lower (LS-3) members of the LS that were deposited in shallow, dysoxic, weakly stratified, freshwater environments. Source rocks of the second organic facies mainly contain type II1–II2 kerogens with mixed macerals of AOM, internites, and vitrinites. It is geochemically differentiated from the algal-dominated organic facies by its relatively low abundance of C30 4-methylsteranes and lighter δ13C values in the range of −27.20‰ to −28.67‰. Three oil groups are identified by their biomarkers and stable carbon isotopes. The first two groups (A and B) are probably end-members of two major oil families (A and B) that correspond to the algal-dominated organic facies and algal–terrestrial organic facies, respectively. Most of the discovered oils belong to group A oils that are characterized by a high abundance of C30 4-methylsteranes and heavy δ13C values and show a good correlation with the algal-dominated organic facies in LS-2. Group B oils are found only within the LS-1 and LS-3 reservoirs, and they are recognized by their relatively low content of C30 4-methylsteranes and lighter δ13C values, showing a close relation to the algal–terrestrial source facies within the LS-1 and LS-3 members, respectively. Group C oils display intermediate biomarker features and stable carbon isotope values and are interpreted to be a mixture of group A and B oils. The oil–source correlation reveals a strong control of organic facies on the geographic distribution of oil groups or oil fields in the basin.