Energy Exploration & Exploitation

Old Mesoproterozoic−Cambrian successions have been regarded as an important frontier field for global oil and gas exploration in the 21st century. This has been confirmed by a recent natural gas exploration breakthrough in the Sinian and Cambrian strata, central Sichuan Uplift, Sichuan Basin of SW China. However, the accumulation mechanism and enrichment rule of these gases have not been well characterized. This was addressed in this work, with aims to provide important guidance for the further exploration while enriching the general studies of the oil and gas geology in the old Mesoproterozoic–Cambrian strata. Results show that the gas field in the study area is featured by old target layers (Sinian–Lower Cambrian), large burial depth (>4500 m), multiple gas-bearing intervals (the second and fourth members of the Sinian Dengying Formation and the Lower Cambrian Longwangmiao Formation), various gas reservoir types (structural type and structural–lithologic type), large scale (giant), and superimposing and ubiquitous distribution. The giant reserves could be attributed to the extensive intercalation of pervasive high quality source rocks and large-scale karst reservoirs, which enables a three-dimensional hydrocarbon migration and accumulation pattern. The origin of natural gas is oil cracking, and the three critical stages of accumulation include the formation of oil reservoirs in Triassic, the cracking of oil in Cretaceous, and the adjustment and reaccumulations in the Paleogene. The main controlling factor of oil and gas enrichment is the inherited development of large-scale stable paleo-uplift, and the high points in the eastern paleo-uplift are the favorable area for ​natural gas exploration.

The Dengying Formation of Neoprotozoic age deposited in north Sichuan Basin, China, is dominated by dolomitic strata containing microbial carbonates. Thirteen cyanobacteria forms, one oncolite and two stromatolitic structures have been identified. Different microfacies may be related to different microbe forms or assemblages as well as depositional environments. Potential hydrocarbon reservoirs in microbial carbonates are of low porosity and permeability. Microbialites develop in the members Z₂dn¹, Z₂dn², and Z₂dn⁴. The member Z₂dn¹ and Z₂dn² lying in the lower part, dominated by thrombolitic and spongiostromata dolostone, with three reservoir intervals of overall 190 m thick. Laminite and stromatolitic dolostone are the most important in member Z₂dn⁴, with three reservoir intervals of 119 m thick. Microbial carbonate reservoirs in members Z₂dn¹ and Z₂dn² were effected by two stages of fresh water dissolution, three stages of burial dissolution, and one stage of hydrocarbon invasion. But one stage of fresh water dissolution, two stages of burial dissolution, and three stages of hydrocarbon invasion modified the reservoirs of member Z₂dn⁴. The dominant factors for microbial reservoirs were microbial textures and development of Mianyang-Changning intracratonic sag.

The high-porosity dolomite reservoirs of the Lower Ordovician Tongzi Formation (Fm.) were widely developed in the Sichuan Basin of southern China. The characteristics and developing mechanisms of the high-porosity dolomite reservoirs under the control of fourth-order sequence boundaries are discussed. In the Tongzi stage of the Early Ordovician, the Sichuan Basin was in a restricted platform facies in an evaporated shallow seawater environment. From the western to eastern regions of the basin, the Tongzi Fm. was serially developed in a tidal flat-lagoon-high-energy shoal depositional system. The evaporated seawater consequently led to dolomitization by way of the refluxing model. The Tongzi Fm. dolomites were subdivided into four coarsening-upward fourth-order sequences. Many tiny dissolution pores were formed in the dolomite beneath the four fourth-order sequence boundaries due to syn-sedimentation meteoric water erosion. Exposure above the seawater due to the short-term fall of the relative sea level consequently led to contemporaneous meteoric erosion. The Tongzi Fm. dolomites in the belt surrounding the Central Paleo-uplift were further subaerially dissolved by meteoric water due to tectonic uplift in the Guangxi Movement since the end of the Silurian period. Therefore, dolomitization, syn-sedimentation meteoric erosion under the fourth-order sequence boundaries, and meteoric karst during the Guangxi tectonic uplift jointly controlled the development of the Tongzi Formation high-porosity dolomite reservoirs. In the eastern and southeastern Sichuan Basin, the favourable reservoirs are the high-energy shoal dolomites that were eroded by meteoric water under fourth-order sequence boundaries. Around the Central Paleo-uplift, the favourable reservoirs are the dolomites dissolved by subaerial meteoric karst during the Guangxi Movement.

Bio-precursors of organic matter, referring to formerly living precursors, can influence content and distribution of organic pores significantly. However, insufficient attention has been paid in previous studies. To research the impact of bio-precursors of organic matter on shale organic pores, we conducted palynology and thin section analysis, total organic carbon analysis, and N₂ gas absorption experiments on the Wufeng and Longmaxi Formations shales and kerogen samples from the Shuanghe outcrop section in southern Sichuan Basin, China. Generally, there are three bio-precursor assemblages being developed from bottom to top in the Wufeng and Longmaxi Formation, namely benthic algae, benthic–planktonic algae, and planktonic algae assemblages. Porosity in kerogen contributes greatly to shale porosity, accounting for 13 − 53% of total porosity. The total porosity and mesopore volume of samples (kerogen and shale) dominated by benthic algae are higher than those by planktonic algae. Pore size distributions of kerogen samples containing mainly benthic algae and planktonic algae are unimodal and multimodal type, respectively, when the pore diameter is larger than 5 nm. The different features between benthic and planktonic algae assemblages could be attributed to their different hydrocarbon generation potential and biological structure. Smaller fractal dimension of pores in kerogen samples mainly containing planktonic algae suggested that the planktonic algae are responsible for smoother pores in shales.

The effects of brittle minerals in shale diagenesis on shale pores remain controversial and it is difficult to quantify directly. However, the relationship between brittle minerals and shale pores could provide indirect guidance regarding diagenesis processes in post-mature marine shales. In this study, the pore size distribution was determined, and the relationship between pore volume and shale composition was examined in shale samples with different total organic carbon contents from the Wufeng and Longmaxi Formations, with the objective of distinguishing pore size ranges in organic matter and inorganic minerals, respectively, and studying shale diagenesis. The samples of the Wufeng and Longmaxi shales are composed of clay minerals, calcite, dolomite, quartz, feldspar, and some minor components. The pore size distributions, which were determined using nitrogen adsorption isotherm analysis of shale and kerogen, show similar trends for pore sizes less than approx. 6.5 nm but different trends for larger pore sizes. Mercury injection saturation shows that macropores account for 14.4–22% of the total pore volume. Based on a series of crossplots describing the relationships between shale composition and pore volume or porosity associated with different pore sizes as well as on scanning electron microscopy observations, organic matter pores were found to comprise most of the micro-mesopores (pore diameters < 6.5 nm). Organic matter pores and intraparticle pores associated with carbonate constitute the majority of mesopores (pore diameters 6.5–50 nm). Finally, interparticle pores associated with quartz comprise the majority of the macropores. The mesopores associated with carbonate were formed by dissolution during diagenesis, whereas the macropores associated with quartz are the remainders of the original interparticle pores. Mesopore volumes increase with increasing carbonate content while macropore volumes decrease due to the ‘pore size controlled solubility’ effect, which causes dissolved calcium carbonate to precipitate in larger macropores.

The dolomites of the Middle Permian Qixia Formation have been important targets of natural gas exploration in the Sichuan Basin for decades. However, more and more exploration and research indicate that the formation of the reservoir might be related to karstification. To testify this hypothesis, we conduct comprehensive outcrop, core, and logging analyses based on a case study in the representative northwestern Sichuan Basin, which has obtained exploration breakthroughs recently. Results show that the Qixia dolomite reservoirs are mainly developed within fine-crystalline dolomites formed by a series of diagenetic modifications, which can be further divided into three types according to the macro- and micro-occurrences of dolomites: euhedral-subhedral crystalline dolomites in the quasi-stratiform karst system (mean porosity and permeability is 3.51% and 3.11 mD, respectively), euhedral-subhedral crystalline dolomites in the leopard porphyritic karst system (mean porosity and permeability is 3.36% and 1.22 mD, respectively), and allotriomorphic mosaic crystalline dolomites with residual parent rock fabrics (mean porosity and permeability is 0.94% and 0.92 mD, respectively). Their reservoir qualities decrease along the order. The formation mechanism of the reservoir is shoal-controlled karst. The preservation of residual intergranular pores within the thin-layer grainstones of shoal facies provides favorable channels for karst water. In the vadose zone, the heterogeneous dissolution within grainstones leads to the formation of leopard porphyritic dissolution features. In the phreatic zone, the karst water flowing along the stratiform grainstones results in the formation of quasi-stratiform dissolution features. The karst system is filled with loose carbonate sands and gravels, whose reservoir properties are far superior to parent rocks, and they can provide migration channels for the hydrothermal fluids with rich Mg²⁺ in the burial stage. The replacement of hydrothermal fluid results in the redistribution of pores and vugs of inter-fillings within karst system and the formation of intercrystalline pores and residual vugs, but the reservoir space of parent rocks keeps the same as the original condition. Therefore, the exploration of the Qixia dolomite reservoir should be changed to shoal-controlled karst.

The Sichuan Basin is one of the richest oil and gas basins in China. The Middle Permian units (the Qixia and Maokou Formations) in the northwest Sichuan Basin have great potential for gas exploration. A new thermal history was reconstructed using the integrated thermal indicators of apatite and zircon (uranium–thorium)/helium ages, zircon fission tracks, and vitrinite reflectance data. The modeled results indicated that the northwest Sichuan Basin experienced gradual cooling, during which the heat flow at Middle Permian time (70–90 mW/m²) decreased to its current level of approximately 50 mW/m². This study used basin modeling to reconstruct the paleo-pressure, which showed that the Middle Permian in the northwest Sichuan Basin generally developed overpressure. The pressure evolution of the Middle Permian can be divided into three stages: (1) a slight overpressure stage (T₂–T₃), (2) an intensive overpressure stage (J₁–K₂), and (3) an overpressure reduction stage (K₂–present). Oil cracking and rapid tectonic subsidence are key factors that affect overpressure. The evolution of temperature–pressure has great significance with respect to hydrocarbon accumulation.

Weathered-crust karst carbonate is developed in the third submember of the fourth member of the Middle Triassic Leikoupo Formation (Lei₄³ submember) in the Longgang area of Sichuan Basin, China, and acts as an important oil and gas reservoir. To reconstruct the paleogeomorphology of the weathered-crust karst, we analyzed the seismic thickness of the interval from the erosional unconformity surface on the top of the Leikoupo Formation to the karst at the bottom of the third member of the Xujiahe Formation (Xu₃ member), based on existing three-dimensional seismic and drilling data, and the sedimentary characteristics of the Leikoupo and Xujiahe formations. There are three secondary types of geomorphological unit, namely the karst highlands, the karst transitional zone, and the karst basin, and these have distinct karst water development patterns and hydrological conditions that determine the intensity of karstification and reservoir quality. Among them, the karst highlands have a poor reservoir capacity due to their long-term exposure above the water table, which resulted in severe denudation. The karst transitional zone features the superimposition of multiple periods of strong karstification, and this has resulted in high-quality reservoir conditions in the karst monadnocks but poor reservoir conditions in the karren. The karst basin represents a drainage area that experienced weak karstification, and the reservoir capacity is generally poor, although some good reservoirs were developed in shoals. Paleogeomorphological maps provide excellent guides to finding karst monadnocks in karst transitional zones, and monadnocks should serve as the main targets of exploration in the weathered-crust karst reservoir on top of the Lei₄³ submember.

The Late Triassic Xujiahe Formation is a key target for tight gas in the northern Sichuan Basin. Thin section, scanning electron microscopy, X-ray diffraction, porosity and permeability analyses have been performed to delineate the diagenesis and reservoir characteristics of Xujiahe sandstone. The results show that the Xujiahe Formation contains feldspathic litharenite, litharenite, sublitharenite and quartzarenite sandstone. Sandstones of the Xujiahe Formation are characterized by low feldspar content and both secondary and micro-fracture porosity. Porosity and permeability analyses of 185 core samples show a broad but low porosity range from 0.79 to 10.43% (average 4.55%) and wide but low permeability range (0.0021–26.001 mD, average 0.449 mD). The higher permeabilities result from micro-fracturing. Strong mechanical compaction plays a more important role in reducing primary porosity of sandstone than cementation during eodiagenesis. Carbonate cement is detrimental to reservoir porosity. Early carbonate cement precipitated from depositional water during eodiagenesis can block primary pores while late carbonate cement formed during mesodiagenesis can fill secondary pores. Quartz cement shows a slight relationship with porosity and permeability. There is a positive relationship between grain-coating chlorite and porosity and permeability. The effect of diagenesis on the reservoir quality of Xujiahe tight gas sandstone is greater that depositional environment during deep burial.

Recent exploration work in the Tazhong district has gradually transferred to the exploitation of high and over mature oils in deep and ultra-deep layers. This has proved problematic, however, as the distribution of crude oils in the Tazhong is complex. This means that the geochemical characterization of high and over mature oils, especially for light crude oils, have become increasingly important. The stability of concerted ring structure of aromatics makes them having stronger thermal stability and resistance to biodegradation. This means that there are abundant aromatic compounds in high and over mature oils. This study presents a series of geochemical analyses of the maturity parameters of 89 crude oils from the Tazhong area, including stable carbon and hydrogen isotope analyses of compounds from 43 light crude oils. These analyses are then compared with other data from the Tazhong Number I fault zone, as well as the Tazhong Number 10 and Tazhong Uplift structural zones. Results show that the geochemical parameters of oils from Tazhong Number I fault zone generally encompass a wider range than those from the Tazhong Number 10 structural zone, which indicates that the Tazhong Number I slope belt is more active than its counterpart structural belt and generates oils with more complex geochemical characteristics. The positive correlation between the toluene/methyl cyclohexane ratio and the dibenzothiophene/phenanthrene ratio, as well as with the naphthalene/phenanthrene ratio indicates that aromatization parameters can be used to evaluate the maturity of light crude oils, and there may be inherited relationships between toluene and methyl cyclohexane in crude oils.

In order to keep the formation pressure be larger than the dew-point pressure to decrease the loss of condensate oil, cyclic gas injection has been widely applied to develop condensate gas reservoir. However, because the heterogeneity and the density difference between gas and liquid are significant, gas breakthrough appears during cyclic gas injection, which apparently impacts the development effects. The gas breakthrough characteristics are affected by many factors, such as geological features, gas reservoir properties, fluid properties, perforation relations between injectors and producers, and operation parameters. In order to clearly understand the gas breakthrough characteristics and the sensitivity to the parameters, Yaha-2 condensate gas reservoir in Tarim Basin was taken as an example. First, the gas breakthrough characteristic of different perforation relations by injecting natural gas was studied, and the optimal relation was achieved by comparing the sweep efficiency. Then, the designs of orthogonal experiments method were employed to study the sensitivity of gas breakthrough to different parameters. Meanwhile, the characteristic parameters, such as gas breakthrough time, dimensionless gas breakthrough time, and sweep volume, were calculated and the prediction models were achieved. Finally, the prediction models were applied to calculate the gas breakthrough time and sweep volume in Yaha-2 condensate gas reservoir in Tarim Basin. The reliability of the model was verified at the same time. Please see the Appendix for the graphical representation of the abstract.

The condensate gas reservoirs of the Jurassic Ahe Formation in the Dibei area of the Tarim Basin, northwest China are typical tight sandstone gas reservoirs and contain abundant resources. However, the hydrocarbon sources and reservoir accumulation mechanism remain debated. Here the distribution and geochemistry of fluids in the Ahe gas reservoirs are used to investigate the formation of the hydrocarbon reservoirs, including the history of hydrocarbon generation, trap development, and reservoir evolution. Carbon isotopic analyses show that the oil and natural gas of the Ahe Formation originated from different sources. The natural gas was derived from Jurassic coal measure source rocks, whereas the oil has mixed sources of Lower Triassic lacustrine source rocks and minor amounts of coal-derived oil from Jurassic coal measure source rocks. The geochemistry of light hydrocarbon components and n-alkanes shows that the early accumulated oil was later altered by infilling gas due to gas washing. Consequently, n-alkanes in the oil are scarce, whereas naphthenic and aromatic hydrocarbons with the same carbon numbers are relatively abundant. The fluids in the Ahe Formation gas reservoirs have an unusual distribution, where oil is distributed above gas and water is locally produced from the middle of some gas reservoirs. The geochemical characteristics of the fluids show that this anomalous distribution was closely related to the dynamic accumulation of oil and gas. The period of reservoir densification occurred between the two stages of oil and gas accumulation, which led to the early accumulated oil and part of the residual formation water being trapped in the tight reservoir. After later gas filling into the reservoir, the fluids could not undergo gravity differentiation, which accounts for the anomalous distribution of fluids in the Ahe Formation.

High-yield natural gas was discovered in well SN4 in the Ordovician Yingshan Formation in the Tarim Basin. The gas is found in unusual, silicified, carbonate reservoirs. According to the degree of silicification, the silicified reservoirs can be divided into a lower section of silicified carbonates, a middle section of limestone, and an upper section of silicified carbonates. The silicified carbonates are mainly composed of quartz and calcite, in which the reservoir space mostly occurs as vugs, inter-crystalline pores of quartz, and partial fractures. Porosity varies widely, ranging from 3 to 20.5% with strong heterogeneity. The homogenization temperatures of fluid inclusions in quartz and calcite show that the silicification temperatures were 150–190°C, with characteristics of high temperature/low salinity and low temperature/high salinity. The ⁸⁷Sr/⁸⁶Sr ratios of secondary calcite are 0.709336–0.709732, which are significantly higher than that of concurrent seawater, indicating that the hydrothermal fluid originated from the deep clastic strata or the basement (sialic rock). The δ¹³C values of the secondary calcite are similar to that of the surrounding limestone, indicating that the carbon in the secondary calcite is derived from the limestone strata, and that the secondary calcite is the product of dissolution and re-precipitation resulting from interaction between the silica-bearing hydrothermal fluids and surrounding limestones. The silicification of silica-bearing hydrothermal fluid was significantly controlled by strike-slip faults. The fluids ascending along the fault zone and branch faults interacted with the surrounding limestone in the Yingshan Formation. As a result, a large amount of quartz and secondary calcite were formed together with various types of secondary pores, resulting in excellent reservoirs.

Recent natural gas discoveries indicate that non-karstification-dominated reservoirs exist in the intracratonic Ordos Basin. This study examines the sedimentological and geochemical characteristics needed to clarify the depositional model and diagenetic evolution process of this newly discovered reservoir type. The depositional environment of the dolomite reservoir can be characterized as a tidal flat that grew from the Central Paleo-uplift to the eastern depression by cyclic progradation on an epeiric platform. A tidal flat sequence can extend laterally as a progradational wedge in each cycle of sea level fluctuation. The sheet-shaped peritidal shoal facies associations patched on the wedge represent potential dolomite reservoirs and can be recognized by the presence of doloarenite that has been altered into a vaguely relict grained-texture by diagenesis. Although continuing destructive diagenesis has led to reservoir densification, burial dolomitization and burial dissolution with facies selectivity have tended to occur in peritidal shoal facies associations, thus improving the quality of the dolomite reservoirs. These models provide new insights for targeting deep dolomite hydrocarbon reservoirs in intracratonic basins.

Tight sandstone gas is on the first position of unconventional natural gas sources, which can be developed under today’s technical conditions. In recent years, tight sandstone gas reservoirs have been found in several wells in the Linxing area, eastern margin of Ordos Basin, China. In this article, a variety of methods, including cast thin sections, X-ray diffraction analysis, scanning electron microscope, and drill core data were used to study the petrological characteristics and their influences on tight sandstone reservoir in coal-bearing strata of the Linxing area. Based on the analysis of thin section, it can be concluded that the sandstone reservoir is essentially constituted of lithic sandstone as well as lithic arkose and feldspathic litharenite. Cement types are complicated, including carbonate minerals, clay minerals, and quartz overgrowth. Illite, kaolinite, chlorite, illite–smectite mixed layer, and chlorite–smectite mixed layer are found in clay minerals. Compared with other clay minerals, illite is in the dominant position. Pores can be divided into residual intergranular pore, intragranular dissolution pore, intergranular dissolution pore, cement dissolution pore, intercrystalline pore, and microcrack in sandstone reservoir of the Linxing area. Quartz has an average content of 68% with the feature of low compositional maturity and plays a major role in increasing porosity due to dissolution and protecting of quartz. Feldspar dissolution plays a role in decreasing porosity because the by-product materials of feldspar dissolution remain in original place, instead of being transported to other areas. Dissolution pores are 2–20 µm and may be filled with kaolinite, illite, or halite. It is worth mentioning that grain-coating chlorite may be of sufficient thickness to protect reservoirs along with the increasing content of chlorite, which is testified by the crossplot between the chlorite and porosity when the absolute content of chlorite is less than 1.5%.

In order to study the characteristics of the gas supply and development mode in sweet spots of Sulige tight gas reservoir in Ordos Basin, China, a mathematical model was developed for the typical lenticular reservoirs in tight gas reservoirs, and its analytical solution was obtained. The ideal model was calculated by using the analytical solution. Analysis of the production data indicated a clear boundary between the high- and low-permeability regions of the lenticular reservoir, and the boundary will supply gas to the low-permeability region. The reliability of this finding was validated by real production data. The development mode of the lenticular reservoir was obtained, that is the high-permeability area was first used during the initial production; when the pressure wave reached the boundary in the high-permeability region, the production showed a pseudo-steady state; further increase of the production pressure exceeding the threshold of the surrounding low-permeability region triggered the utilization of the low-porosity and low-permeability regions. The established model can provide useful guidance for the development of similar tight gas reservoirs.

Studies have found that the Permian is another important stratum for petroleum exploration except the Jurassic coal measures within Turpan–Hami Basin recently. However, the knowledge of the depositional environments and its petroleum geological significances during the Middle–Late Permian is still limited. Based on the analysis about the sedimentological features of the outcrop and the geochemical characteristics of mudstones from the Middle Permian Taerlang Formation and Upper Permian Quanzijie Formation in the Taoshuyuanzi profile, northwest Turpan–Hami Basin, this paper makes a detailed discussion on the Middle–Late Permian paleoenvironment and its petroleum geological significances. The Middle–Upper Permian delta–lacustrine depositional system was characterized by complex vertical lithofacies assemblages, which were primarily influenced by tectonism and frequent lake-level variations in this area. The Taerlang Formation showed a significant lake transgression trend, whereas the regressive trend of the Quanzijie Formation was relatively weaker. The provenance of Taerlang and Quanzijie Formations was derived from the rift shoulder (Bogda Mountain area now) to the north and might be composed of a mixture of andesite and felsic volcanic source rocks. The Lower Taerlang Formation was deposited in a relatively hot–dry climate, whereas the Upper Taerlang and Quanzijie Formations were deposited in a relatively humid climate. During the Middle–Late Permian, this area belonged to an overall semi-saline water depositional environment. The paleosalinity values showed stepwise decreases from the Lower Taerlang Formation to the Upper Quanzijie Formation, which was influenced by the changes of paleoclimate in this region. During the Middle–Late Permian, the study area was in an overall anoxic depositional environment. The paleoenvironment with humid climate, lower paleosalinity, anoxic condition, and semi-deep to deep water during the deposition of the Upper Taerlang Formation was suitable for the accumulation of mudstones with higher TOC values.

The dissolution of gypsum rock is of significance to study because it affects the formation of hydrocarbon reservoirs, cap rocks and evaporite deposits. However, the characteristics and mechanism of the dissolution process remain unclear. Here, we present data from experiments performed to address this issue. The experiments simulate various geological conditions, including different diagenetic stages of burial under different fluid types. The diagenetic stages include: 30°C and 0.3 MPa for the epidiagenetic stage; 60°C and 13 MPa for the early diagenetic stage; 100°C and 27 MPa for the middle diagenetic stage; and 150°C and 43 MPa for the late diagenetic stage. The different fluid types include pure water representing continental water, seawater, 0.3 wt.% CO₂ solution representing meteoric water, and a 0.2 wt.% acetic acid solution representing organic fluid. We also carried out the experiments on limestones and dolomites, because these rocks also occur in saline water sedimentary systems with gypsum rocks. Experimental results show that lithology, fluid type and temperature–pressure conditions can all affect dissolution. In terms of lithology, gypsum rocks dissolve more easily than limestones and dolomites. Fluid type has little effect on the dissolution of gypsum rock, and gypsum is soluble in all four types of fluids. In contrast, limestones and dolomites are almost insoluble in pure water and seawater, but show clear dissolution in CO₂ and acetic acid solutions. The data indicate that gypsum rock has a dissolution peak close to the early diagenetic stage. In contrast, limestones and dolomites have dissolution peaks in the CO₂ solution at the early–middle diagenetic stage, and do not show a peak in the acetic acid solution under surficial temperature–pressure conditions. The dissolution rates of limestone and dolomite show different trends with increasing temperature and pressure: limestone dissolution rates decline whereas dolomite dissolution rates increase. Therefore, we infer that the physicochemical properties of a rock are important drivers of dissolution.

Hydrous and anhydrous isothermal experiments on n-pentane and n-octadecane were conducted at 300–375℃ for durations up to 1094 h to evaluate the cracking and hydrolysis of hydrocarbons, using fused silica capillary capsules as micro-reactors. The chemical compositions of the gaseous products during cracking of n-octadecane at 350 and 375℃ were methane, ethane, propane, and n-butane. The aqueous product in the hydrolysis of n-pentane and n-octadecane at 300–375℃ was alcohol. Alkenes and hydrogen were not detected throughout all the isothermal experiments. Results showed that the gaseous yields were characterized by higher contents of wet gas than those in natural gas accumulations. Mechanisms regulating the enrichment of methane in reservoirs should be further studied. The hydrolysis and oxidation of hydrocarbon were relatively limited in the absence of iron-bearing mineral buffers, suggesting that hydrocarbons might be more stable in iron-poor reservoirs (e.g. carbonate and quartz arenite) than in iron-bearing-mineral-rich ones (e.g. mudstone and arkose) under deep burial conditions. The absence of hydrogen was ascribed to its high diffusion rate in fused silica than in gold tube; any hydrogen produced in the reaction tends to diffuse out of the fused silica capsule with no or limited hydrogen accumulation, similar to those in geological environment. The diffusion of hydrogen should be considered during calculating the volume and pressure changes in the thermal cracking of oil to gas in reservoirs, because the loss of hydrogen would result in a decrease in the conversion rate of oil to gas.

There are two kinds of relationships between magmatism and the generation of hydrocarbons from source rocks in petroliferous basins, namely: (1) simultaneous magmatism and hydrocarbon generation, and (2) magmatism that occurs after hydrocarbon generation. Although the influence of magmatism on hydrocarbon source rocks has been extensively studied, there has not been a systematic comparison between these two relationships and their influences on hydrocarbon generation. Here, we present an overview of the influence of magmatism on hydrocarbon generation based on the results of simulation experiments. These experiments indicate that the two relationships outlined above have different influences on the generation of hydrocarbons. Magmatism that occurred after hydrocarbon generation contributed deeply sourced hydrogen gas that improved liquid hydrocarbon productivity between the mature and overmature stages of maturation, increasing liquid hydrocarbon productivity to as much as 451.59% in the case of simulation temperatures of up to 450°C during modelling where no hydrogen gas was added. This relationship also increased the gaseous hydrocarbon generation ratio at temperatures up to 450°C, owing to the cracking of initially generated liquid hydrocarbons and the cracking of kerogen. Our simulation experiments suggest that gaseous hydrocarbons dominate total hydrocarbon generation ratios for overmature source rocks, resulting in a change in petroleum accumulation processes. This in turn suggests that different exploration strategies are warranted for the different relationships outlined above. For example, simultaneous magmatism and hydrocarbon generation in an area means that exploration should focus on targets likely to host large oilfields, whereas in areas with magmatism that post-dates hydrocarbon generation the exploration should focus on both oil and gas fields. In addition, exploration strategies in igneous petroliferous basins should focus on identifying high-quality reservoirs as well as determining the relationship between magmatism and initial hydrocarbon generation.