Hydrocarbon accumulation depth limit and implications for potential resources prediction

Key factors controlling hydrocarbon accumulations in Ordovician carbonate reservoirs in the Tazhong area, Tarim basin, western China

In order to speed up the development and utilization of hydrothermal energy, it is essential to assess the potential of geothermal resources in petroliferous basins. In this paper, the distribution of reservoirs (aquifers) and the characteristics of geothermal fields have been studied systematically based on geological, geophysical, well drilling, temperature, and sample test data obtained from the major petroliferous basins of China. It has been found that some of the porous sandstone formations in these petroliferous basins are major geothermal reservoirs and are extensively thick and widely distributed. In general, the geothermal gradient in China is higher in the eastern basins and lower in the western basins. On average, the geothermal gradient is above 30 °C/km in the Bohai Bay, Songliao, and Subei basins. The geothermal resource abundance is also higher in eastern China and in the Beibuwan basin in southern China, and the geothermal source forming condition is better, followed by the Ordos, Qaidam, and Sichuan basins in Central China. Other potential basins include the Tarim and Junggar basins in western China, where the geothermal gradient ranges between 21 and 22 °C/km, on average. In this paper, three methods, stochastic simulation, unit volumetric, and analogy, were used for the assessment of geothermal resources. Using the stochastic simulation and unit volumetric methods, the geothermal resources, annual recovered geothermal resources, geothermal water resources, and thermal energy of water in 11 basins or blocks of up to 4000 m deep were calculated. Grading evaluation criteria were established by considering the heterogeneity of geothermal reservoirs. The results showed that the petroliferous basins are very rich in geothermal resources. The annual recoverable resources reach 1626.8 × 106 tons of standard coal, in which grade I, grade II, and grade III resources are 641.9 × 106, 298.6 × 106, and 686.3 × 106 tons of standard coal, respectively. The results demonstrate that the development and utilization of geothermal energy in oilfields has a huge potential for industrial production and family use, and a great significance for the development of green oilfields. With the high demand of heat, the eastern oilfields with high geothermal resource abundance should be the first to be considered for the production and utilization of geothermal energy, followed by the central and western oilfields.

Deep marine petroleum systems are critical to the energy supply in China, making them a key focus of petroleum exploration and research. A comprehensive understanding of the diversity and effectiveness of deep marine source rocks is essential for objectively evaluating their resource potential. However, significant challenges remain, including the unclear heterogeneity of source rocks, ambiguous hydrocarbon origins, and uncertainties regarding source rock effectiveness, all of which hinder accurate resource assessments. To address these issues, this study examines the geological characteristics of deep marine source rocks in two major petroliferous basins in China—the Sichuan Basin and the Tarim Basin. Drawing on field outcrop profiles and newly acquired drilling data, five geological models are established to characterize the formation and distribution of deep marine source rocks. Furthermore, stable carbon isotope and biomarker analyses of different source rock types underscore their distinct roles in hydrocarbon accumulation within deep marine petroleum systems. This study also provides a preliminary discussion of the unconventional petroleum resource potential of carbonate source rocks. The results highlight the pronounced heterogeneity of deep marine source rocks, which is largely governed by sedimentary facies distributions. Multiple lines of evidence suggest that the stable carbon isotopes of kerogen are minimally affected by thermal maturity and can still retain valuable paleoenvironmental information even during high-overmature stages. Although hydrocarbon cracking at high maturity reduces the absolute concentration of biomarkers, certain proxies remain effective for characterizing source rock properties and performing oil–source correlation. During the black oil stage, specific biomarkers can still provide insights into source rock characteristics. In the Tarim Basin, deep marine petroleum systems are not solely sourced from organic-rich shales but are also significantly influenced by carbonate source rocks. Two primary hydrocarbon origins are identified: (1) source rocks of varying lithofacies within the different sedimentary facies in the Yuertusi Formation and (2) contributions from source rocks in other formations, including the Ordovician and Sinian. The resource potential of carbonate source rocks is substantial, with hydrocarbons not only migrating into conventional reservoirs but also potentially remaining trapped within the source rocks. Under favorable economic conditions, these carbonate reservoirs could become promising targets for unconventional petroleum exploration and development. Therefore, potential exploration targets for unconventional petroleum resources include the Middle Permian Maokou Formation in the Sichuan Basin and its adjacent areas, as well as the marlstone reservoirs of the Lower Cambrian Yuertusi Formation and the Lower Xiaoerbulak Formation in the Tarim Basin.

Correlation and difference between conventional and unconventional reservoirs and their unified genetic classification

Controls on hydrocarbon accumulation by facies and fluid potential in large-scale lacustrine petroliferous basins in compressional settings: A case study of the Mesozoic Ordos Basin, China

Late-stage is defined here as the period when Neotectonism occurred since 5.1 Ma. Most petroliferous basins in China lie in the areas where Neotectonism occurred intensively. In recent years, Chinese petroleum geologists have paid much attention to late-stage petroleum accumulation. The PL19-3 giant oilfield is situated where faulting activities occurred violently during Neotectonism. To understand the mechanism of lat-stage rapid accumulation, we discussed the most important aspects responsible for the formation of the giant oilfield, including oil generation, active oil-source rock occurrence, fault activity and fault conduits, late-stage rapid oil injection as well as the distinguishing indicators. This study shows that: (1) sufficient oil was supplied to the PL19-3 field since 5.1 Ma because the PL19-3 structure was surrounded by four sags in which three intervals of high-quality source rocks remained active during Neotectonism; (2) densely distributed faults and high porosity/permeability sandstone carrier beds comprised the effective conduit system for oil migration and injection; (3) oil migrated along the faults and charged the PL19-3 structure rapidly by means of seismic pumping which was triggered by frequent earthquakes during Neotetonism. It is documented that elevated reservoir temperature, abnormal geothermal gradients and abnormally high homogenization temperatures of the fluid inclusions are the indicators for late-stage rapid oil accumulation.

Roles of gypsum/salt-bearing sequence in hydrocarbon accumulation and storage

Hydrocarbon accumulation characteristics in basement reservoirs and exploration targets of deep basement reservoirs in onshore China

The pore structure and mineral characteristics affect the accumulation and migration of hydrocarbons in shale, which determines the production capacity of shale oil. In this study, shale samples from the Chang 7 member of the Ordos Basin in China were selected to investigate the pore space characteristics, the effect of hydrocarbon accumulation on pore heterogeneity, and the hydrocarbon migration changes based on fractal theory, and a series of experiments were conducted involving X-ray diffraction (XRD), total organic carbon (TOC), Soxhlet extraction, and low-temperature nitrogen (N2) and carbon dioxide (CO2) adsorption. Then, the factors affecting extraction efficiency in shale pores were discussed. The interparticle pores contributed most to the accumulation of shale oil, and the organic matter (OM) pores contributed positively to the adsorption of hydrocarbons. The accumulation of hydrocarbons in the pore space did not increase the heterogeneity of the shale pore structure. The contents, states, and positions of hydrocarbons changed during the extraction process. Hydrocarbons were redistributed on the pore surface after Soxhlet extraction, and the heterogeneity of hydrocarbon adsorption and pore surface roughness were improved. Some heavy hydrocarbons and adsorbed components were pyrolyzed, resulting in the gradual escape of the adsorbed layer in the large pores. However, the free oil in the small pores diffused to the large pores and reaggregated on the surface, restoring a stable adsorption layer. The extraction rate was closely related to the pore throat structure and the wettability of mineral surfaces. The configuration between pores and throats had a crucial influence on the extraction rate. A high proportion of meso-pores, which effectively connect micro- and macro-pores, had a higher diffusion efficiency and a higher extraction rate. The OM pores with high energy adsorption were located in the micro-pores, and the shale oil existed in a dissolved state with high mobile capacity. The wettability of mineral surfaces affected the adsorption behavior during extraction, and strong oil wetting promoted hydrocarbon re-adsorption in clay minerals, so that the volume of micro-pores was smaller after extraction.

The conditions and modelling of hydrocarbon accumulation in tight sandstone reservoirs: A case study from the Jurassic Shaximiao formation of western Sichuan Basin, China

Junggar Basin is one of the important petroliferous basins in China. Based on sedimentology, palaeogeography, geochemical characteristics, tectonic thermal evolution and other aspects, this study analyzes the characteristics and distribution law of source rocks, and predicts the total oil and gas resources of Jurassic in the basin. Middle and Lower Jurassic is the main hydrocarbon source rock strata of Jurassic, and a large set of thick coal and dark mudstone are developed on delta, shore-shallow lake and deep lake facies in the basin, among which Badaowan Formation is 200 ~ 800 m thick; Xishanyao Formation is 50m ~ 550m thick, which has great development prospect, but there are few exploration results at present. Through geochemical index analysis and thermal evolution simulation of source rocks, the middle and lower Jurassic source rocks are mostly medium-good source rocks, and the distribution and thermal evolution degree of mature source rocks in the south and east of the basin are higher than those in the north and west of the basin, so they have the conditions for mass production of hydrocarbons.

The Xihu Depression at the shelf of the East China Sea is a petroliferous basin with excellent exploration potential. The Eocene Pinghu Formation has become a recent oil and gas exploration target and as the critical hydrocarbon-bearing stratigraphic layer in the basin. However, studies specifically examining the characteristics of hydrocarbon distribution and the controlling factors of reservoirs in the Kongqueting area remain limited. The lack of in-depth hydrocarbon accumulation model research restricts subsequent exploration. In this paper, based on data from drilling, 3D seismic, well test, and geochemical analysis, we found that coal bed-related hydrocarbon source rocks were widely occurred in the Pinghu Formation in the Kongqueting area. The source rocks provide good hydrocarbon supply of near-source and distant-source to reservoir. The river sands were connected laterally and stacked vertically, forming a pattern characterized by ‘lateral succession and vertical superposition’ indicative of good quality of reservoir. During the deposition period of the Pinghu Formation, two large sets of regional cap rock (P3 and P7) were excellent sealing rock. The sand reservoir was interbedded with shale layers, forming a Mille-feuille type of reservoir-seal pair. Faults formed at the early stage of the formation of basin serve as conduits for hydrocarbon migration, governing both the spatial distribution of hydrocarbon-bearing strata and the types of hydrocarbon accumulations. These faults were instrumental in facilitating the formation of extensive oil and gas accumulations. This paper establishes a hydrocarbon accumulation model in the Kongqueting area, characterized as ‘dual hydrocarbon supply from source, upper oil, and lower gas, good reservoir-seal pair, hydrocarbon migration through fault conduit’.

Based on the sedimentary and tectonic background of the Termit Basin, this paper focuses on the Upper Cretaceous Yogou Formation and uses organic geochemistry, logging, oil testing and seismic data to analyze the primary control factors of the hydrocarbon accumulation and establish corresponding model in order to predict favorable exploration target zones of hydrocarbon reservoirs. This study demonstrates that the Upper Cretaceous Yogou Formation is a self-generation and self-accumulation type reservoir. The Yogou Formation hydrocarbon reservoirs in the Koulele area are controlled by four factors: (1) the source rock is controlled by a wide range of YS1-YS2 marine shale, (2) the sandstone reservoir is controlled by the YS3 underwater distributary channel and storm dunes, (3) migration of hydrocarbons is controlled by faults and the regional monocline structure, and (4) the accumulation of hydrocarbons is controlled by lateral seal. The structures in the western Koulele area are primarily reverse fault-blocks with large throws, and the structures in the east are dominantly fault-blocks with small throws (co-rotating and reverse) and a fault-nose. In the western Koulele area, where the facies are dominated by storm dunes on a larger scale, it is easier to form lithologic reservoirs of sandstone lens. In the eastern Koulele area, high-quality channel sandstone reservoirs, fault-blocks with small throws, and the monocline structure benefit for the formation of updip pinch out lithologic traps, fault lithologic reservoirs and fault-nose structural reservoirs. Future exploration targets should be focused in the western storm dunes zone and eastern distributary channel sand zone with small fault-blocks.

Detailed compositional analysis of hydrocarbons in soil gases above multi-horizon petroleum deposits – A case study from western Poland

Multi-stage hydrocarbon migration and accumulation of Permian petroleum system in the Zaysan Basin, NE Kazakhstan