Hydrocarbon Accumulation Mechanism Research Articles

The Production Analysis and Exploitation Scheme Design of a Special Offshore Heavy Oil Reservoir—First Offshore Artificial Island with Thermal Recovery

More and more offshore heavy oil resources are discovered and exploited as the focus of the oil and gas industry shifts from land to sea. However, unlike onshore heavy oil reservoirs, offshore heavy oil reservoirs not only have active edge and bottom water but also have different exploitation methods. In this paper, a typical special heavy oil reservoir in China was analyzed in detail, based on geology–reservoir–engineering integration technology. Firstly, it is identified as a self-sealing bottom water heavy oil reservoir by analyzing its geological characteristics and hydrocarbon accumulation mechanism. Secondly, the water cut is initially controlled by oil viscosity, but subsequently, by reservoir thickness through the analysis of oil and water production data. Thirdly, the bottom oil–water contact of the reservoir was re-corrected to build an accurate 3D geological model, based on the production history matching of a single well and the whole reservoir. Lastly, a scheme of thermal production coupled with cold production was proposed to exploit this special reservoir, and the parameters of steam, N2, and CO2 injection and production were optimized to predict oil production. This work can provide a valuable development model for the efficient exploitation of similar offshore special heavy oil reservoirs.

Molecular and Carbon Isotopic Compositions of Crude Oils from the Kekeya Area of the Southwest Depression, Tarim Basin: Implications for Oil Groups and Effective Sources

Molecular and stable carbon isotopic compositions of 32 crude oils from the Kekeya area of the Southwest Depression, Tarim Basin, were analyzed comprehensively to clarify oil groups and trace oil sources. The results indicate that lacustrine shale sequences within the Upper-Middle Permian Pusige Formation (P3–2p) are the major effective oil sources; the thermal maturation effects exert the crucial impact on geochemical compositions of crude oils. In the Kekeya structural belt, crude oils produced from the Lower-Neogene, Middle-Paleogene and Middle-Cretaceous sandstone reservoirs were generated mainly from deeply buried P3–2p at the late-to-high maturity stage. These condensates are depleted in terpanes, steranes and triaromatic steranes and enriched in adamantanes and diamantanes. The evaluated thermal maturity levels of crude oils by terpanoids and steranes are generally lower than that of diamondoids, implying at least two phases of oil charging. In the Fusha structural belt, oils produced from the Lower-Jurassic reservoirs (J1s) of Well FS8 were generated from the local P3–2p at the middle to late mature stage. On the contrary, these oils are relatively rich in molecular biomarkers such as terpanes and steranes and depleted in diamondoids with only adamantanes detectable. The P3–2p-associated oils can migrate laterally from the Kekeya to Fusha structural belt, but not to the location of Well FS8. The Middle-Lower Jurassic (J1–2) lacustrine shales as the major oil sources are limited to the area around Well KS101 in the Kekeya structural belt. Crude oils originated from J1–2 and P3–2p can mix together within the Cretaceous reservoirs of Well KS101 by presenting the concurrence of high concentrations of terpane and sterane biomarkers and diamondoids as well as 2–4% 13C-enriched n-alkanes than those of P3–2p derived oils. This study provides a better understanding of hydrocarbon sources and accumulation mechanisms and hence petroleum exploration in this region.

In-situ hydrocarbon formation and accumulation mechanisms of micro- and nano-scale pore-fracture in Gulong shale, Songliao Basin, NE China

By conducting experimental analyses, including thermal pyrolysis, micro-/nano-CT, argon-ion polishing field emission scanning electron microscopy (FE-SEM), confocal laser scanning microscopy (CLSM), and two-dimensional nuclear magnetic resonance (2D NMR), the Gulong shale oil in the Songliao Basin was investigated with respect to formation model, pore structure and accumulation mechanism. First, in the Gulong shale, there are a large number of pico-algae, nano-algae and dinoflagellates, which were formed in brackish water environment and constituted the hydrogen-rich oil source materials of shale. Second, most of the oil-generating materials of the Qingshankou Formation shale exist in the form of organo-clay complex. During organic matter thermal evolution, clay minerals had double effects of suppression and catalytic hydrogenation, which expanded shale oil window and increased light hydrocarbon yield. Third, the formation of storage space in the Gulong Shale was related to dissolution and hydrocarbon generation. With the diagenesis, micro-/nano-pores increased, pore diameter decreased and more bedding fractures appeared, which jointly gave rise to the unique reservoir with dual media (i.e. nano-scale pores and micro-scale bedding fractures) in the Gulong shale. Fourth, the micro-/nano-scale oil storage unit in the Gulong shale exhibits independent oil/gas occurrence phase, and shows that all-size pores contain oils, which occur in condensate state in micropores or in oil-gas two phase (or liquid) state in macropores/mesopores. The understanding about Gulong shale oil formation and accumulation mechanism has theoretical and practical significance for advancing continental shale oil exploration in China.

Geochemical characteristics and gas-washing accumulation mechanism of hydrocarbon from the Xihu Sag, East China Sea Basin

For many petroleum production plays with large amounts of natural gas produced, their hydrocarbon accumulation processes have been reported to be commonly involved with gas-washing. The gas generation intensity of the Xihu Sag, East China Sea Basin is up to 6 × 106 t/km2, which is the primary driving force for gas-washing to occur. 18 oils and 20 gas samples produced from the Eocene – Oligocene sandstone reservoirs in the Xihu Sag has been geochemically characterized to delineate the controlling factor of the gas-washing and in turn better understand the hydrocarbon accumulation mechanism of the study area. The results show that the natural gas is primarily mature-highly mature coal-type gas based on their carbon isotope characteristics. The oils are believed to belong to a same oil family with a similar thermal maturity and have been gas-washed based on either their molecular fingerprints or other geochemical characteristics. The high toluene/n-heptane ratio (Tol/nC7) and high n-alkane mass depletion (Q) of the oils further indicate the occurrence of gas washing. A good correlation between either the reservoir depth or the gas generation intensity of the source kitchen and the n-alkane mass depletion of the crude oil indicate reservoir depth and gas generation intensity are the two primary controlling factors on the gas washing of the study area. In order to further delineate the effects of evaporative fractionation or migration fractionation on the hydrocarbon reservoir, we introduced a new cross plot of n-alkanes mass depletion (Q) versus adamantane/diamantine (A/D) to type the oils related to the gas washing in the study area. The meaning of this paper for the exploration of oil and gas resources will be related to the understanding of different gas washing mechanism, so as to further enhance the exploration efficiency.

Hydrocarbon accumulation and resources evaluation: Recent advances and current challenges

Conventional petroleum exploration targets have become increasingly complex recently. Although geological research of unconventional oil and gas resources has received much attention in recent years, such resources also face many complex geological and scientific problems. In this context, the 8th International Symposium on Hydrocarbon Accumulation Mechanisms and Petroleum Resources Evaluation was held in Beijing from 21 to 23 October, 2022. Experts presented and discussed their latest research findings on this topic relating to both conventional and unconventional oil and gas resources. They also discussed various development strategies for the petroleum industry taking into account the global objectives of “carbon peaking and carbon neutrality” to mitigate the impacts of climate change. Six significant theoretical advances and some new technologies were introduced at this conference. These advances related to the “Whole Petroleum System” theory, shale oil and gas exploration, deep and ultra-deep petroleum exploitation, clean energy issues, and alternative types of unconventional oil and gas resources. In response to these technological advances, four major current challenges were identified. These challenges related to the petroleum industry’s ongoing growth and development in the context of carbon-neutrality goals, the evolution of hydrocarbon laws relating to petroleum accumulations and their exploitation, organic and inorganic effects on petroleum generation and accumulation mechanisms, and artificial intelligence applications related to hydrocarbon prediction. Cited as: Jin, Z. Hydrocarbon accumulation and resources evaluation: Recent advances and current challenges. Advances in Geo-Energy Research, 2023, 8(1): 1-4. https://doi.org/10.46690/ager.2023.04.01

Architecture, genesis, and the sedimentary evolution model of a single sand body in tight sandstone reservoirs: A case from the Permian Shan-1–He 8 members in the northwest Ordos Basin, China

A single sand body is defined as a geological unit that is continuous vertically and horizontally but separated from the upper and lower sand bodies by mudstone or impermeable intercalation. The architecture of a single sand body is significant in the determination of hydrocarbon accumulation mechanisms in gas reservoirs, especially for exploitation of multiple tight sandstone gas (TSG) reservoirs. One such example is the gas reservoirs in the Tianhuan Depression, China, where the architecture and genesis of sand bodies are poorly understood. Based on the geologic background and sedimentary characteristics, the evolution of the distributary channel in the Tianhuan Depression has been examined using data from geological outcrops, cores, and well logs. The results showed that sand body architecture depends on the evolution of channel systems, and the scale and size of the channel are controlled by the sedimentary environment. Three kinds of sedimentary microfacies (distributary channel, channel mouth bar, and interdistributary bay) are mainly developed in the study area, and four types of single sand body stacking patterns (isolated, vertically superimposed, laterally tangentially superimposed, and horizontally bridged sand bodies) have formed in such a depositional environment. The target strata (Shan-1 and He-8 members) provide an ideal object for studying the evolution of the river and the architecture of the sand bodies. During the early stage of deposition, the sediment supply was insufficient, with restricted meandering river deltas dominating and sand bodies mostly existing as isolated types. Until the middle period of deposition, the sediment supply suddenly increased, the sedimentation rate accelerated with the decrease in the lake water base level, and the channel evolved into a large-scale braided river delta, generally forming superimposed sand bodies. By the late period of deposition, the provenance supply was reduced again; although braided river delta deposits were still dominant, the channel scale was restricted, and the sand bodies were predominantly isolated and horizontally bridged types. This work establishes a sedimentary evolution model for tight sandstone gas reservoirs, that is, a complete cycle of river evolution from small scale to large scale to terminal weakening, and discusses the genetic mechanism of single sand body architecture in such a depositional model.

A Comparative Study on the Microstructure and Petrophysical Properties of Undeformed and Naturally Deformed Shales

Structural deformation is one of the main impacts responsible for understanding the hydrocarbon accumulation mechanism. Predicting its function in gas storage and migration in a microscopic scale is thus a significant issue in predicting reservoir quality. The purpose of this article is to make a comparative study on the microstructure and petrophysical properties of undeformed and naturally deformed shales developed in the Southeast Sichuan Basin. The results show that (1) organic pores, ranging from 10 to 200 nm, are more developed in undeformed shale, whereas carbonate solvopores, clay-hosted pores, and microfractures are dominant in deformed shale. (2) Undeformed shales have Dubinin–Radushkevich (DR) CO2 adsorbed contents ranging between 0.009 and 0.018 g, DR CO2 micropore surface areas of 3.90–15.59 m2/g, and Dubinin–Astakhov (DA) CO2 micropore volumes of 0.002 and 0.035 cc/g. Naturally deformed shales have larger DR CO2 adsorbed contents, DR CO2 micropore surface areas, and DA CO2 micropore volumes, typically in the ranges of 0.019–0.031 g, 13.15–20.97 m2/g, and 0.006–0.012 cc/g, respectively. (3) Undeformed shales have N2 adsorbed contents ranging between 1.94 and 6.03 cc/g, Brunauer–Emmett–Teller (BET) N2 mesopore and macropore surface areas of 0.55–7.35 m2/g, and Barrett–Joyner–Halenda (BJH) N2 mesopore and macropore volumes of 0.002 and 0.006 cc/g. Naturally deformed shales have larger N2 adsorbed contents, BET N2 mesopore and macropore surface areas, and BJH N2 mesopore and macropore volumes, typically in the ranges of 5.72–14.45 cc/g, 7.47–17.64 m2/g, and 0.005–0.015 cc/g, respectively. (4) All samples have a unimodal micropore size distribution with a distinct peak associated with a 1.5 nm micropore fraction and have a multimodal mesopore and macropore size distribution. Naturally deformed shales show more homogeneous pore size distribution curves with morphological consistency than undeformed shales, indicating that structural deformation can significantly influence pore structural heterogeneity. (5) Deformed shales exhibit higher porosity and permeability compared to the undeformed samples due to the open pore-fracture network associated with the inorganic pores and microfractures. Average porosity and permeability in deformed shales can be 1.8 and 15 times higher than those in the undeformed shales. We conclude that the microstructural heterogeneity from strong to weak and the changes of a relatively single organic pore-dominated pore system to complex pores and microfractures dominated the pore-fracture system within shales due to structural deformation being the key cause of the quantitatively and qualitatively studied microstructure and petrophysical property differences.

Hydrocarbon accumulation mechanism in the far-source reservoirs of Dongsha Uplift of the Pearl River Mouth Basin, northern South China Sea

There are a lot of exploration examples of far-source reservoirs, but the description of the connotation and accumulation mechanism is very rare. The Dongsha Uplift is one of the major oil-producing areas in the eastern Pearl River Mouth Basin in the northern South China Sea. The uplift lacks generally hydrocarbon source rock and is far from the generative kitchen, making it a typical far-source oil and gas reservoir. The accumulation mechanism of crude oil in the reservoirs are still unknown. By systematically comparing biomarkers, nitrogenous compounds and isotopic characteristics of the crude oil and source rocks with those in the neighboring depressions, and combining with fracture, sand body, unconformity migration conduits and barrier conditions, this paper simulates oil and gas migration paths and formation time with Pathway and IES software, and analyzes oil and gas accumulation process from a dynamic perspective. We found that the deep lacustrine hydrocarbon source rocks of the Wenchang Formation in the H26 Sag of the Huizhou Depression reached peak oil production at the end of the Hanjiang Formation deposition. Influenced by the strong tectonic activities at the final deposition of the Hanjiang and Yuehai formations, two episodes of hydrocarbon charging occurred at the top of the Dongsha Uplift. The accumulation of hydrocarbons far from the source rocks in the Dongsha uplift is mainly controlled by the efficient carrier system at hydrocarbon generation period. The oil is mainly accumulated in L4-1 and L11-1 oil fields through the long-distance stepped migration mode. The spatial and temporal relationship between hydrocarbon generation of source rock and episode of fault activity are mainly responsible for accumulation in the far-source reservoirs of the Dongsha Uplift.

Petroleum phase evolution at high temperature: A combined study of oil cracking experiment and deep oil in Dongying Depression, eastern China

• The evolution rule of phase envelopes during oil cracking to gas was revealed. • Cricondentherm decreases with the increase of oil cracking. • Gas invasion leads to the change of phase state and phase diagram of reservoirs. • Evaporation fractionation is a key factor affecting the deep light oil reservoirs. • Formation model of condensate gas and volatile oil reservoirs were proposed. Numerous light oil reservoirs have been discovered in the lower part of Mbr 4 of Paleogene Shahejie Fm in the Dongying Depression, Bohai Bay Basin, eastern China. The petroleum phases and reservoir-forming models are crucial to understanding the hydrocarbon accumulation mechanisms in the deep lacustrine layers. The deep formation temperature and pressure, the PVT phase diagrams, as well as the burial-thermal history were simulated and restored based on the results of oil cracking experiments and the analysis of measured data of geological sections in the Dongying Depression. The process and laws of hydrocarbon accumulation were summarized. The cricondentherm envelopes depict a series of variations when the molar percentages of CO 2 , CH 4 , C 2-5 , and C 6 + in the fluid composition change. In the process of oil cracking, the cricondenbar increases with the increase in the molar percentage of CH 4 . With the increase in molar percentage of C 2-5 and C 6 + , the cricondenbar decreases continuously. According to simulations of fluid composition and phase state, the oil reservoirs in this area are primarily oil-rim condensate gas reservoirs and volatile oil reservoirs. Based on burial-thermal history recovered under the constraint of measured vitrinite reflectance (VRo), the homogenization temperature of fluid inclusions suggests two main periods of petroleum charging: in the late deposition of the Mbr 3 of the Paleogene Shahejie Fm and Guantao Fm in the Eocene. In the second charged stage, the oil cracking gas from deep places in the depression was injected into the primary oil and gas reservoirs, causing the changes and differentiation of fluid phases in the reservoirs. The gas invasion and evaporative fractionation caused by late natural gas filling are key factors for the formation of light oil reservoirs.

Fluid inclusion characteristics of the Jurassic reservoir and hydrocarbon accumulation process in the eastern Kuqa Depression, Tarim Basin

There has been significant progress in hydrocarbon exploration of the eastern Kuqa Depression, Tarim Basin, whose Jurassic reservoir is a key area for abundant hydrocarbon with poorly understood accumulation mechanism. This study conducts an integrated investigation comprising petrographic observations, microthermometry measurements, and fluorescence spectroscopy analyses on fluid inclusions to reconstruct hydrocarbon accumulation history in the Jurassic reservoir. These conclusions are combined with biomarker characteristics to reveal the burial history and thermal evolution of the study area. The results show that (1) there were two episodes of oil charging that occurred at 6~4 Ma and 4~2 Ma, respectively. The QGF experiment response and yellow fluorescent oil inclusions indicated that low-maturity medium crude oil from the Triassic source rocks was expelled into the upper Ahe Formation. In the second charging stage, some mature oil generated from Jurassic source rocks was charged into the reservoir of the Kezilenuer and Yangxia formations, while the condensate from the Triassic source rocks was migrated upward to the Jurassic reservoir, consistent with smaller QGF-E intensity values and blue-white fluorescent petroleum inclusions. (2) There were two kinds of hydrocarbon accumulation models including the lower-generation and upper-storage and the self-generated and self-stored models. (3) It was noted that active faults were developed under the compression stress to provide channels for hydrocarbon vertical migration. Moreover, the early reservoir was destroyed resulting from the strata denudation and a large amount of crude oil was escaped to the surface. The findings of this study can help for better understanding of hydrocarbon accumulation mechanism in the eastern Kuqa Depression and provide theoretical guidance for further oil and gas exploration.

Dynamic reconstruction of the hydrocarbon generation, accumulation, and evolution history in ultra-deeply-buried strata

The evolution mechanism of hydrocarbons in ultra-deeply-buried and ultra-old strata is the core issue of petroleum geology moving towards Deep Earth. Reconstructing the evolutionary history of ultra-deeply-buried hydrocarbons is the key to shedding light on deep hydrocarbon accumulation and evolution mechanisms. Furthermore, it can help point out directions for oil and gas exploration in Deep Earth. Anyue gas field in the central Sichuan Basin is the Frontier of deep natural gas exploration in China. This study selected the natural gas reservoirs of the Upper Sinian Dengying Formation in the central Sichuan Basin as the research object. By integrating analysis of natural gas geochemical characteristics, source rock evaluation, reservoir bitumen-source correlation, inclusion analysis, one-dimensional and two-dimensional hydrocarbon accumulation simulations, the generation and evolution of hydrocarbons in different structural regions, namely the inherited paleo-uplift and slope area in central Sichuan Basin, have been dynamically restored and compared. The results show that: 1) The natural gas of the ultra-deeply-buried Sinian Dengying formation in central Sichuan is typical oil-cracking gas from the paleo-oil reservoir. The Sinian gas is mainly sourced from the Qiongzhusi/Maidiping Formation. 2) The formation of Sinian gas reservoirs includes three stages: the formation of paleo-oil-reservoirs; the cracking of paleo-oil-reservoirs into paleo-gas-reservoirs; the adjustment of the paleo-gas-reservoirs. 3) Source rock and reservoir evaluation, quantitative solid bitumen analysis, and hydrocarbon accumulation simulation show that the natural gas accumulation conditions in the slope area are better than in the inherited uplift area. The scale of the paleo-oil-reservoirs in the slope area may be greater than that in the inherited uplift area.

Effects of types and content of clay minerals on reservoir effectiveness for lacustrine organic matter rich shale

As a promising supplement of China’s petroleum production, the lacustrine shale, compared with the marine shale, is characterized by higher clay mineral content, which has significant impacts on the hydrocarbon reservoir quality. Controlled by the paleo-lacustrine background and thermal maturity, the clay mineral contents vary tremendously in different shale systems. This study targets on three shale series formed in different basin types, namely the Lucaogou Formation shale (Junggar Basin), the Chang 7 Member shale (Ordos Basin), and the Qingshankou Formation shale (Songliao Basin), where the Junggar Basin was a saline lacustrine basin and the latter two were freshwater-brackish lacustrine basins. We find that the composition and content of clay minerals are considerably varied among the three shales that the clay mineral content of the Lucaogou formation shale is smaller than that of the Chang 7 Member and Qingshankou Formation, and the content of illite in the Chang 7 shale is lower than that in the Qingshankou shale. The occurrence of clay minerals has crucial effects on pore structures, that is the pore-filling clays has indiscernible contribution to the storage space, like in the Lucaogou shale, but those developing along the shale laminae can improve the storage capacities to form inter-granular pores and micro-fractures such as in Chang 7 Member and Qingshankou Formation. The development of clay mineral-related pores and fractures is controlled by thermal maturity (Ro) and affected by the content of terrigenous minerals. This pore structure alteration derived by the clay mineral occurrence types further affects the hydrocarbon contents. In the Lucaogou shale, the oil content is inversely proportional to clay mineral contents, while in Qingshankou Formation, the oil content is even higher than that of the adjacent felsic silt laminae due to the favorable development of micro-fractures and inter-granular pores in clay mineral laminae. The high clay mineral content in lacustrine shales in China make it necessary to investigate the clay mineral evolution to evaluate the hydrocarbon generation potential, pore structures, hydrocarbon contents, and hydrocarbon accumulation mechanisms in shale systems.

Hydrocarbon Accumulation Mechanism of Ordovician in the Halahatang Area, Tarim Basin—Evidence From Organic Geochemistry

As an important oil and gas-bearing area in the Tarim Basin, the Halahatang Area has great potential for resource exploration. However, the research on oil and gas sources and the filling period of the Lower Paleozoic Ordovician is still limited. In this study, the organic geochemical analysis of source rocks, the simulation technology of hydrocarbon generation evolution basin, the distribution characteristics of fluid inclusions, and the measurement of uniform temperature are used and combined with the stable isotope of natural gas and the characteristics of oil-source biomarkers, and the process of oil and gas accumulation is restored. The results show that: ①The Cambrian source rock is the main contributor to Ordovician crude oil in the Halahatang Area, and its crude oil shows the characteristics of lightweight, rich chain hydrocarbons, and poor aromatic hydrocarbons. The composition of C7 compound shows the advantage of n-heptane, which belongs to type I kerogen. The biomarker compounds show the characteristics of high content of long-chain tricyclic terpane and high Ts/Tm values, and the crude oil is considered to be a highly mature sapropelic kerogen source oil. ②The carbon isotopes of methane and ethane of Ordovician natural gas in the Halahatang Area are light (from −35.6 to −29.5‰), showing obvious characteristics of sapropelic gas. ③There are three stages of the oil and gas accumulation process in Ordovician reservoirs in the Halahatang Area. In the middle and late Caledonian periods, the source rock reached the hydrocarbon generation threshold and began to generate oil. The late Hercynian period was the main accumulation period, and the Himalayan period was dominated by dry gas filling. ④The crude oil generated in the Middle-Late Caledonian periods migrated along the faults and conductive layers and finally accumulated in the high parts of the structure in the north. The migration of oil and gas in the late Hercynian period was limited by the bitumen produced by early biodegradation. Since the asphalt plugging condensate gas has almost failed to cause gas invasion from the reservoir, the Ordovician reservoir still maintains the characteristics of crude oil-associated gas, forming an oil and gas reservoir with a gas cap.

Shale Oil Enrichment Mechanism of the Paleogene Xingouzui Formation, Jianghan Basin, China

Organic-rich lacustrine shales are widely developed in China, and they have long been simply regarded as homogeneous source rocks, which restricts the understanding of intrasource oil accumulation. At present, the study of the LXF (Lower Member of the Xingouzui Formation) in the Jianghan Basin as an unconventional oil reservoir is still in its infancy, and the hydrocarbon accumulation mechanism is still unclear. Geochemical and mineralogical studies were carried out on a suite of samples from the 100-m-thick sequence, i.e., LXF II Oil Bed, by using XRD, SEM, MICP, and Rock-Eval pyrolysis. The results show that the II Oil Bed is rich in carbonate and poor in clay, so it shows a good fracturing tendency. The high degree of heterogeneity in mineral composition leads to frequent interbedding of different lithofacies. In the II Oil Bed, intercrystalline pores, interparticle pores, and intraparticle pores are developed, and micro-fractures are often observed. However, the main pore types, pore size distribution, and connectivity are quite different among lithofacies, and the carbonate-rich lithofacies have better reservoir capacity. The OM (organic matter) abundance of the II Oil Bed varies greatly and generally ranges from fair to very good. Coupled with its early-mature to mature Type II OM, it is considered to have the characteristics required for oil generation. Comprehensive analysis shows that the II Oil Bed has good shale oil exploration prospects, and the enrichment of shale oil in the sequence is the result of multiple factors matching. Firstly, high organic matter abundance is the material basis for shale oil enrichment. Secondly, thermal maturity is a prerequisite, and the difference in burial depth leads to the differential enrichment of shale oil in different areas. Thirdly, pores and micro-fractures developed in shale not only provide space for hydrocarbon storage, but also form a flow-path network. Finally, multi-scale intrasource migrations are key processes ranging from the scale of lithofacies to the intervals, which further results in the differential shale oil enrichment in different lithofacies and intervals. Considering the hydrocarbon generation capacity and reservoir quality, the prospective depth for shale oil exploration in the study area is >1350 m. The findings of this study can help in the better-understanding of the shale oil enrichment mechanism, and the optimization of future exploration strategies.

Multi-Type Hydrocarbon Accumulation Mechanism in the Hari Sag, Yingen Ejinaqi Basin, China

With the successful development of unconventional hydrocarbons, the production of unconventional hydrocarbons has increased rapidly. However, a single conventional or unconventional model is not suitable for the mechanism of hydrocarbon accumulation in a given basin or sag. Based on data from drilling, logging, and geophysical analysis, the hydrocarbon accumulation mechanism in the Hari sag in the Yingen-Ejinaqi basin, China, was analyzed. There are three sets of source rocks in the Hari sag: the K1y source rocks were evaluated as having excellent source rock potential with low thermal maturity and kerogen Type I-II1; the K1b2 source rocks were evaluated as having good source rock potential with mature to highly mature stages and kerogen Type II1-II2; and the K1b1 source rocks were evaluated as having moderate source rock potential with mature to highly mature stages and kerogen Type II1-II2. Reservoir types were found to be conventional sand reservoirs, unconventional carbonate-shale reservoirs, and volcanic rock reservoirs. There were two sets of fault-lithologic traps in the Hari sag, which conform to the intra-source continuous hydrocarbon accumulation model and the approaching-source discontinuous hydrocarbon accumulation model. The conclusions of this research provide guidance for exploring multi-type reservoirs and multi-type hydrocarbon accumulation models.

Hydrocarbon accumulation characteristics in the inter-salt shale oil reservoir in the Eocene Qianjiang Depression, Hubei Province, China

Research on the migration and accumulation of hydrocarbons in shale oil reservoirs composed solely of organic-rich mudstones has not received adequate attention. The Qianjiang Formation provides an opportunity for research on the hydrocarbon accumulation mechanism due to the presence of hydrocarbon migration characteristics in its inter-salt organic-rich fine-grained rocks. In this study, the inter-salt stratum of the tenth rhythmite can be classified into three sections: lower, middle, and upper. The middle section is mostly composed of laminated marlstones and laminated calcite-bearing argillaceous dolomicrites, whereas, the lower and upper sections mostly contain bedded muddy dolomicrites and glauberite. Geochemical analysis was conducted to study the organic matter enrichment mechanism and shale oil accumulation characteristics. The results indicate that the middle section has the highest organic matter abundance, with poor organic matter abundance displayed by the other sections. The C27/C29 sterane and extended tricyclic terpane ratios suggest that the organic matter types in different sections of the inter-salt stratum differ, and the middle section has more aquatic organic matter than other sections. The sedimentary structures and salinity-related parameters indicate that the middle section was developed in a deep stratified saline lake and that the other sections were formed in a shallow hypersaline lake. This study shows that high biological productivity and stratified lake water facilitated the enrichment of organic matter, resulting in high organic matter content in the middle section. The oil saturation index and hydrocarbon composition suggest that hydrocarbons were differentially accumulated in the inter-salt stratum of the tenth rhythmite. The maturity-related biomarkers further revealed the possible migration paths of hydrocarbons in the inter-salt stratum. Based on the aforementioned analyses, this study established an inter-salt shale oil accumulation model. This study suggests that hydrocarbons were released from the mature source rocks in the deep depression with differential migration laterally and vertically within the inter-salt stratum. The study of the Qianjiang Depression shows that organic-rich fine-grained rocks cannot only form in situ sweet spots but may also possess migrated hydrocarbons inside them, which are characterized by high organic matter abundance and oil saturation. This research provides a new case for further understanding hydrocarbon accumulation inside source rocks.

Characteristics of hydrocarbon migration and accumulation in the Lower Jurassic reservoirs in the Tugerming area of the eastern Kuqa Depression, Tarim Basin

The hydrocarbon migration and accumulation process in the Kuqa Depression are complex. In recent years, the Jurassic strata have recorded hydrocarbon discoveries in the Tugerming area of the eastern Kuqa Depression. However, it is a new exploration area, and the characteristics of hydrocarbon accumulation are unclear, restricting oil and gas exploration and development. In our study, the deeply-buried and shallow-buried Jurassic strata in the Tugerming area are the research objects. Quantitative fluorescence technique and the observation of fluid inclusions are implemented on the selected samples of Jurassic reservoirs to determine the stages and times of hydrocarbon charging. Gas chromatography-mass spectrometry analysis for saturated hydrocarbons is used to identify the origin of organic matter in oils. Combined analytical data with the reconstructed histories of burial, thermal evolution and tectonic evolution, allow simulating the hydrocarbon migration and accumulation process in the Tugerming area. The results show that two categories of hydrocarbon accumulation mechanisms (Burnham and Sweeney, 1989). The first type is acted as the type of “self-generation and self-storage and late accumulation”. Three stages of hydrocarbon charging have occurred in the deeply-buried Lower Jurassic reservoirs, represented by two wells (Tudong 2 and Tuge 4). The charging time is the early-middle stage of Miocene Kangcun Formation (18–9 Ma), forming the yellow or yellow-green fluorescent oil inclusions and paleo-oil reservoir. During the sedimentary period of the late Kangcun Formation to the early Kuqa Formation (9–5 Ma), the reservoir experienced massive condensate oil migration, corresponding to blue-white fluorescent oil inclusions. Large-scale natural gas was expelled into the reservoirs since the deposition stage of Kuqa Formation (5–0 Ma), and then accumulated in the trap controlled by the late Himalayan movement, forming the current gas reservoir. Moreover, the hydrocarbons are generated from Jurassic coal measure source rocks in the Well Tudong 2 based on the characteristics of biomarkers (Burruss et al., 1991). The second type is characterized by “lower source rock and upper reservoir and accumulation in the late or recent period”, developed in the shallow-buried Lower Jurassic reservoirs containing two wells (Tuxi 1 and Mingnan 1). In this case, there are two stages of crude oil charging: mature oil charging in the early-medium Miocene (18–12 Ma) and condensate oil migration in the late Miocene (8–5 Ma). The strata suffered denudation due to the stratigraphic uplifting in the orogenic movement, resulting in the leakage of the early oil reservoir. In both categories, it suggests that the Lower Jurassic reservoirs in the Tugerming area have the favorable potential for oil and gas exploration. The understanding of hydrocarbon migration and accumulation in the Lower Jurassic reservoirs in the Kuqa Depression of Tarim Basin can contribute to the knowledge of the potential to form large oil and gas reservoirs Tugerming Area, and reservoirs of basins with a similar tectonic settings, such as the Jungar Basin.

Hydrocarbon Accumulation Process and Mechanism in the Lower Jurassic Reservoir in the Eastern Kuqa Depression, Tarim Basin, Northwest China: A Case Study of Well Tudong 2 in the Tugerming Area.

The Lower Jurassic reservoir has recently made a significant breakthrough in petroleum exploration in the Tugerming area of the eastern Kuqa depression, Tarim Basin, northwest China. Therefore, it is significantly essential to simulate the hydrocarbon charging process and analyze the accumulation mechanism in the study area. In our study, we mainly combine three geochemical techniques to identify the origin of crude oils and fluid inclusion characteristics in the target well (Tudong 2), including gas chromatography–mass spectrometry (GC–MS), comprehensive two-dimensional GC-time-of-flight MS (GC × GC–TOFMS), fluid inclusion analysis, and quantitative fluorescence technique. Combined comprehensive experiments with a set of burial history and tectonic thermal evolution history realize the reconstruction of the hydrocarbon charging process in the Yangxia formation. The results show that Jurassic coal-bearing source rocks are primary hydrocarbon sources, and there are three hydrocarbon charging events in the Lower Jurassic reservoir. First, the mature oils have expelled into the reservoir during the early-middle period (15–10 Ma) of the Miocene Kangcun Formation, forming yellow fluorescent oil inclusions and most of the quantitative grain fluorescence (QGF) indexes exceed 4. Second, numerous condensate oils have charged into the reservoir in the period of late Miocene Kangcun Formation-early Kuqa Formation (9–6 Ma), accompanied by blue-white oil inclusions and QGF on extract intensity greater than 4. Finally, vast natural gas has accumulated in the reservoir since Kuqa Formation (5–0 Ma), resulting in the adjustment of ancient reservoir and residual bitumen. Interestingly, we find that the hydrocarbon accumulation mechanism is characterized by self-generation and self-storage in the Jurassic Yangxia Formation, and the study area has prominent characteristics of late accumulation. Thus, the evidence obtained from our analysis suggests favorable geological conditions for the formation of a large oil and gas reservoir in the eastern Kuqa Depression.

Geochemical characteristics and factors controlling the deep lithologic reservoirs in Puwei Sag, Dongpu Depression—A Case Study of Well PS20

As the advances of the exploration in shallow layers, petroleum exploration moves toward deep layers has become an inevitable choice. However, the hydrocarbon accumulation mechanism in deep reservoir remains a big challenge for the petroleum exploration. The Dongpu Depression is one of the major petroliferous basins in the Bohai Bay Basin of eastern China. The deep Well PS 20 discovered in the Puwei Sag of Dongpu Depression suggests that there is great prospecting in deep reservoir. In this paper, the geochemical characteristics and main controlling factors of deep lithologic reservoir in the third member of the Paleogene Shahejie Formation (Es3) of Well PS20 are analyzed by means of geological and organic geochemical methods including rock-eval, Gas Chromatgraphy-Mass Spectrometry (GC/MS) and Scanning Electron Microscopy (SEM). The results show that the main source rocks are situated in the middle and lower parts of the third member in the Shahejie Formation of Eocene (Es3M-Es3L). They are characterized by higher organic content (>0.6%), good organic matter (most of them are type II, and some are type I) and higher maturity (Ro>1.0%). The oil-source comparison shows that the origin of the Es3U is a mixture from both local and off-sited sources. The origin of the hydrocarbon in Es3M is from a remote source, and the hydrocarbons in Es3L are indigenous. The reservoir properties reveal that the deep strata have been compacted with increasing depth, and higher oil content only occurred in less tight strata with good physical properties. The deep hydrocarbon reservoir in Puwei Sag is controlled by the source rock quality, reservoir properties and sand body thickness. The reservoir physical properties control the oil and gas accumulation and distribution. Sand thickness controls the oil content and hydrocarbon accumulation. The ultra-thin and thin layers in the lower member of Es3 are characterized by multiple layers (>85% of total layer numbers）and thick reservoir layers (>65% of total thickness). The oil saturation in the ultra-thin and thin layers is much higher than that in the thick layers. Numerous micro-fractures produced by abnormally high pressure should be responsible for the higher oil content. Besides, both sandstone and mudstone layers have high brittle mineral content, which also provides advantageous condition for micro-fractures. The results expand the space for petroleum exploration, strengthen the confidence of the new field to achieve a major breakthrough, and shed light on the long-term development of exploration risk in the new field of Dongpu Depression.

Geodynamic mechanism and classification of basins in the Earth system

The sedimentary basin is a basic geological unit in the Earth system: its formation and evolution are controlled mainly by plate tectonics and geodynamics, which have produced a variety of basin types. The development and evolution of various basins depend not only on the tectonic effect of lithospheric plate but also on sublithospheric, and Earth surface actions. Basin classification schemes based on the theories of platform–geosyncline or plate tectonics could neither include all basin types nor reflect the complex processes of basin formation and evolution. From the viewpoint of Earth system, we proposed a new basin classification scheme based on geodynamic mechanism—that is, lithospheric plate, sublithospheric, and Earth surface actions. In our geodynamic classification, we employed a series of geodynamic settings of basin formation and evolution, including the lithospheric plate, sublithospheric, and Earth surface environments, the dynamic regimes of basin formation and evolution, such as tectonic setting (extension, compression and shearing), the thermal processes and gravity effects, the various natures of basin basement and crustal types (continental, oceanic, or transitional crust), and the history of basin sedimentary filling and tectonic paleogeography successively, as the controlling factors for basin classification.This new geodynamic classification scheme highlights both the role of the lithosphere and the effects of the sublithospheric and the Earth surface actions on controlling the basin formation and evolution. The basic dynamic types of basin classification include the prototype basin forming under a single tectonic, thermal, or gravity regime and the superimposed basin as well as residual basin forming under multistage thermal and/or tectonic regimes. Thus, this classification scheme could provide an evolving understanding of lithosphere, crust–mantle interaction, and geodynamic processes as well as of hydrocarbon accumulation and metallogenic mechanisms in sedimentary basins and would help in the synthetic exploration of various resources.