Hydrocarbon Accumulation Characteristics Research Articles

Hydrocarbon accumulation and orderly distribution of whole petroleum system in marine carbonate rocks of Sichuan Basin, SW China

Based on the situation and progress of marine oil/gas exploration in the Sichuan Basin, SW China, the whole petroleum system is divided for marine carbonate rocks of the basin according to the combinations of hydrocarbon accumulation elements, especially the source rock. The hydrocarbon accumulation characteristics of each whole petroleum system are analyzed, the patterns of integrated conventional and unconventional hydrocarbon accumulation are summarized, and the favorable exploration targets are proposed. Under the control of multiple extensional-convergent tectonic cycles, the marine carbonate rocks of the Sichuan Basin contain three sets of regional source rocks and three sets of regional cap rocks, and can be divided into the Cambrian, Silurian and Permian whole petroleum systems. These whole petroleum systems present mainly independent hydrocarbon accumulation, containing natural gas of affinity individually. Locally, large fault zones run through multiple whole petroleum systems, forming a fault-controlled complex whole petroleum system. The hydrocarbon accumulation sequence of continental shelf facies shale gas accumulation, marginal platform facies-controlled gas reservoirs, and intra-platform fault- and facies-controlled gas reservoirs is common in the whole petroleum system, with a stereoscopic accumulation and orderly distribution pattern. High-quality source rock is fundamental to the formation of large gas fields, and natural gas in a whole petroleum system is generally enriched near and within the source rocks. The development and maintenance of large-scale reservoirs are essential for natural gas enrichment, multiple sources, oil and gas transformation, and dynamic adjustment are the characteristics of marine petroleum accumulation, and good preservation conditions are critical to natural gas accumulation. Large-scale marginal-platform reef-bank facies zones, deep shale gas, and large-scale lithological complexes related to source-connected faults are future marine hydrocarbon exploration targets in the Sichuan Basin.

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

Based on the global basement reservoir database and the dissection of basement reservoirs in China, the characteristics of hydrocarbon accumulation in basement reservoirs are analyzed, and the favorable conditions for hydrocarbon accumulation in deep basement reservoirs are investigated to highlight the exploration targets. The discovered basement reservoirs worldwide are mainly buried in the Archean and Precambrian granitic and metamorphic formations with depths less than 4 500 m, and the relatively large reservoirs have been found in rift, back-arc and foreland basins in tectonic active zones of the Meso-Cenozoic plates. The hydrocarbon accumulation in basement reservoirs exhibits the characteristics in three aspects. First, the porous-fractured reservoirs with low porosity and ultra-low permeability are dominant, where extensive hydrocarbon accumulation occurred during the weathering denudation and later tectonic reworking of the basin basement. High resistance to compaction allows the physical properties of these highly heterogeneous reservoirs to be independent of the buried depth. Second, the hydrocarbons were sourced from the formations outside the basement. The source-reservoir assemblages are divided into contacted source rock-basement and separated source rock-basement patterns. Third, the abnormal high pressure in the source rock and the normal–low pressure in the basement reservoirs cause a large pressure difference between the source rock and the reservoirs, which is conducive to the pumping effect of hydrocarbons in the deep basement. The deep basement prospects are mainly evaluated by the factors such as tectonic activity of basement, source-reservoir combination, development of large deep faults (especially strike-slip faults), and regional seals. The Precambrian crystalline basements at the margin of the intracontinental rifts in cratonic basins, as well as the Paleozoic folded basements and the Meso-Cenozoic fault-block basements adjacent to the hydrocarbon generation depressions, have favorable conditions for hydrocarbon accumulation, and thus they are considered as the main targets for future exploration of deep basement reservoirs.

Seismic Identification and Hydrocarbon Accumulation Characteristics of Submarine Fan in offshore Suriname

In recent years, oil and gas fields have been continuously discovered in the Suriname-Guyana Basin of South Atlantic, the reservoir of which is submarine turbidite sandstone and become one of the hot exploration objectives in the world. Based on the interpretation and analysis of 2D seismic and well data, this paper presents the integrated geological and geophysical evaluation of the Suriname-Guyana basin within Suriname and describes the identification characteristics and hydrocarbon accumulation process of submarine fan in offshore Suriname. The tectonic evolution of this region can be divided into four stages, breakup of Pangea, intracontinental rift, regional uplift and drifting over the South Atlantic. The Upper Cretaceous marks the transition of a transgressive to a regressive system with increasing sediment input from the south west, creating a broad delta plain environment across the shallow offshore area. It has been confirmed that multi-stage submarine fans have developed from Upper Cretaceous to Neogene in offshore Suriname, with overlapping characteristics of multiple erosive surfaces. It is suggested that erosive surface forming local unconformity is the important identification mark of submarine fan. Among them, the Paleogene and Upper Cretaceous submarine fans are the most widely distributed and have the most obvious characteristics on seismic profiles. The bottom of the Paleogene and Upper Cretaceous fans are identified by the erosive surfaces. The fan root has obvious characteristics of cutting valley, forming inter-bedded with the deep-sea facies toward the outer fan, along with litho-logic granularity thinning and scope expansion. The distal parts of the submarine fan are surrounded by abyssal shale, which can form a good source, reservoir and cap configuration. Therefore, turbidite fan sandstone with good source rock and cap configuration is the favorable reservoir.

Petroleum geology of marl in Triassic Leikoupo Formation and discovery significance of Well Chongtan1 in central Sichuan Basin, SW China

In 2022, the risk exploration well Chongtan1 (CT1) in the Sichuan Basin revealed commercial oil and gas flow during test in a new zone – the marl of the second submember of the third member of Leikoupo Formation (Lei-32) of Middle Triassic, recording a significant discovery. However, the hydrocarbon accumulation in marl remains unclear, which restricts the selection and deployment of exploration area. Focusing on Well CT1, the hydrocarbon accumulation characteristics of Lei-32 marl are analyzed to clarify the potential zones for exploration. The following findings are obtained. First, according to the geochemical analysis of petroleum and source rocks, oil and gas in the Lei-32 marl of Well CT1 are originated from the same marl. The marl acts as both source rock and reservoir rock. Second, the Lei-32 marl in central Sichuan Basin is of lagoonal facies, with a thickness of 40–130 m, an area of about 40 000 km2, a hydrocarbon generation intensity of (4–12)×108 m3/km2, and an estimated quantity of generated hydrocarbons of 25×1012 m3. Third, the lagoonal marl reservoirs are widely distributed in central Sichuan Basin. Typically, in Xichong–Yilong, Ziyang–Jianyang and Moxi South, the reservoirs are 20–60 m thick and cover an area of 7500 km2. Fourth, hydrocarbons in the lagoonal marl are generated and stored in the Lei-32 marl, which means that marl serves as both source rock and reservoir rock. They represent a new type of unconventional resource, which is worthy of exploring. Fifth, based on the interpretation of 2D and 3D seismic data from central Sichuan Basin, Xichong and Suining are defined as favorable prospects with estimated resources of (2000–3000)×108 m3.

Origin and Geological Significance of Residual Oil in High-Angle Joint Fissures: A Case Study of the Nadu Formation in Baise Basin, South China

The Baise Basin is a Paleogene pull-apart basin with numerous strike-slip faults which are not favorable for hydrocarbon preservation. The Nadu Formation, research object of this paper, is generally rich in oil and contains a large number of high-angle joint fissures. Analyzing the origin of residual oil in high-angle joint fissures can reveal the hydrocarbon migration and accumulation characteristics of the pull-apart-type basins. Molecular geochemical composition characteristics of crude oil and oil source of the Nadu Formation were discussed based on the saturated hydrocarbon biomarker compound and stable carbon isotope distribution of n-alkanes. The studied samples were selected from four members (E2n1, E2n2, E2n3up, and E2n3low) of the Nadu Formation. The results suggested that the average oil content of E2n1 fissures is 0.32 mg/cm2, and the oil distribution is not uniform. The distribution of oil on the fissures of E2n2 and E2n3 is uniform and complete, and the oil content reaches 0.53 mg/cm2. The oil in the joint fissures of the Nadu Formation is heavy, as the light hydrocarbon is seriously lost during migration. Thus, the oil in the joint fissures is residue after crude oil loses light components during migration. By comparing the molecular biomarker characteristics and stable carbon isotopic compositions, crude oil of the Nadu Formation can be classified into three categories: E2n1, E2n2 + E2n3up, and E2n3low. The E2n1 oils have the lowest maturity and are sourced from the E2n1 source rocks. Moreover, the maturity of E2n2 and E2n3 samples are relatively high. Biomarker and carbon isotope characteristics of the E2n2 and E2n3up oils are similar, indicating that they are derived from the E2n2 + E2n3up source rocks. The E2n3low oils are the mixture of the crude oil generated from the E2n3up source rocks and the E2n3low source rocks. Results presented show that the residual oil of high-angle joint fissures in the Nadu Formation is contributed by adjacent source rocks. The crude oil discharged from the Nadu Formation can only migrate upward along high-angle joints in a short distance, and the migration distance is usually less than 5 m. In conclusion, although the Nadu Formation has developed a large number of high-angle joint fissures, crude oil in the Nadu Formation has not vertically migrated for long distance along the joint fissures. The well-preserved fractures as important shale oil storage spaces indicate that the Nadu Formation has good shale oil exploration potential. The results may provide insights into the origins of hydrocarbons in the Nadu Formation from the Baise Basin and enhanced knowledge for optimizing future exploration and production.

Development, sand control mechanism and hydrocarbon accumulation of beach-bar sandstone in a saline lake basin: A case from the Neogene of southwestern Qaidam Basin, NW China

Based on the data of field outcrops, drilling cores, casting thin sections, well logging interpretation, oil/gas shows during drilling, and oil/gas testing results, and combined with modern salt-lake sediments in the Qinghai Lake, the Neogene saline lake beach-bars in southwestern Qaidam Basin are studied from the perspective of sedimentary characteristics, development patterns, sand control factors, and hydrocarbon accumulation characteristics. Beach-bar sand bodies are widely developed in the Neogene saline lake basin, and they are lithologically fine sandstone and siltstone, with wavy bedding, low-angle cross bedding, and lenticular-vein bedding. In view of spatial-temporal distribution, the beach-bar sand bodies are stacked in multiple stages vertically, migratory laterally, and extensive and continuous in NW−SE trending pattern in the plane. The stacking area of the Neogene beach-bar sandstone is predicted to be 3 000 km2. The water salinity affects the sedimentation rate and offshore distance of beach-bar sandstone, and the debris input from the source area affects the scale and enrichment of beach-bar sandstone. The ancient landform controls the morphology and stacking style of beach-bar sandstone, and the northwest monsoon driving effect controls the long-axis extension direction of beach-bar sandstone. The beach-bars have a reservoir-forming feature of “one reservoir in one sand body”, with thick beach-bar sand bodies controlling the effective reservoir distribution and oil-source faults controlling the oil/gas migration and accumulation direction. Three favorable exploration target zones in Zhahaquan, Yingdong−eastern Wunan and Huatugou areas are proposed based on the analysis of reservoir-forming elements.

Major advancement in oil and gas exploration of Jurassic channel sandstone in Well Bazhong 1HF in northern Sichuan Basin and its significance

In January 2023, Well Bazhong 1HF in the northern Sichuan Basin obtained high-yield industrial oil flow of over 100 cubic meters from the Jurassic channel sandstone for the first time, realizing a major breakthrough. In order to provide more support for further oil and gas exploration in this area, this paper analyzes the sedimentary and reservoir characteristics of the Jurassic Lianggaoshan Formation in Bazhong region of northern Sichuan Basin and their control factors based on the exploration achievements of Well Bazhong 1HF. Then, oil and gas reservoir characteristics and oil and gas sources are comparatively analyzed. Finally, the key technologies for the exploration of channel sandstone oil and gas with multi-stage vertical superimposition, lateral migration, thin reservoir and strong heterogeneity are researched and developed, and the next oil and gas exploration direction in the Lianggaoshan Formation of northern Sichuan Basin is pointed out. And the following research results are obtained. First, in the second member of Lianggaoshan Formation (“Liang 2 Member” for short) in Bazhong region, multi-stage underwater distributary sand bodies of delta front are developed with sandstone thickness of about 25 m and average porosity of 5.6%. The pore types are mainly primary intergranular pores and feldspar/debris intragranular dissolved pores, the pore throat structure is good, and the development of good-quality reservoirs is controlled by the sedimentary microfacies of underwater distributary channel. Second, the oil and gas reservoir of Liang 2 Member is a highly oil-bearing condensate gas reservoir/volatile oil reservoir, whose oil and gas is mainly sourced from the semi-deep lacustrine shale of Liang 1 and 2 Members. Third, channel sand bodies are superimposed and developed continuously in the upper part of Liang 2 and Liang 3 Members, and the source-reservoir configuration is good, with the characteristics of near-source hydrocarbon accumulation and overpressure hydrocarbon enrichment. Fourth, for the channel sandstones with multi-stage vertical superimposition, lateral migration, thin reservoir and strong heterogeneity, the reservoir prediction technology of “high-frequency sequence stratigraphy slice, seismic frequency decomposition and facies-constrained seismic waveform indication inversion” is developed to precisely characterize the “sweet spot” target of narrow channel sandstone, and the key fracturing technology of “dense cutting + composite temporary plugging + high-intensity proppant injection + imbibition and oil-increasing” is formed to realize the large-scale reconstruction of channel sandstone reservoir. In conclusion, the breakthrough of Well Bazhong 1HF in the exploration of Lianggaoshan Formation oil and gas in Bazhong region reveals the huge potential of Jurassic oil and gas exploration in the Sichuan Basin, and plays a positive role in promoting the exploration and development of the Jurassic channel sandstone oil and gas in the Sichuan Basin.

Petroleum geology and sub-source hydrocarbon accumulation of Permian reservoirs in Jinan Sag, eastern Junggar Basin, NW China

According to the latest drilling and the analysis of the burial history, source rock evolution history and hydrocarbon accumulation history, the sub-source hydrocarbon accumulation characteristics of the Permian reservoirs in the Jinan Sag, eastern Junggar Basin, are clarified, and the hydrocarbon accumulation model of these reservoirs is established. The results are obtained in four aspects. First, the main body of the thick salified lake basin source rocks in the Lucaogou Formation has reached the mature stage with abundant resource base. Large-scale reservoirs are developed in the Jingjingzigou, Wutonggou and Lucaogou formations. Vertically, there are multiple sets of good regional seals, the source-reservoir-caprock assemblage is good, and there are three reservoir-forming assemblages: sub-source, intra-source and above-source. Second, dissolution, hydrocarbon charging and pore-preserving effect, and presence of chlorite film effectively increase the sub-source pore space. Oil charging is earlier than the time when the reservoir becomes densified, which improves the efficiency of hydrocarbon accumulation. Third, buoyancy and source-reservoir pressure difference together constitute the driving force of oil charging, and the micro-faults within the formation give the advantage of “source-reservoir lateral docking” under the source rock. Microfractures can be critical channels for efficient seepage and continuous charging of oil in different periods. Fourth, the Jingjingzigou Formation experienced three periods of oil accumulation in the Middle–Late Permian, Middle–Late Jurassic and Late Neogene, with the characteristics of long-distance migration and accumulation in early stage, mixed charging and accumulation in middle stage and short-distance migration and high-position accumulation in late stage. The discovery and theoretical understanding of the Permian reservoirs in the Jinan Sag reveal that the thrust belt has good conditions for forming large reservoirs, and it is promising for exploration. The study results are of guidance and reference significance for oil and gas exploration in the Jinan Sag and other geologically similar areas.

Hydrocarbon dominant migration direction and accumulation mode in Qijiang area, Sichuan Basin, China

The high‐quality hydrocarbon source rocks developed in the Longtan Formation of the Qijiang area and the good reservoir capacity of the overlying dolomite of the Jialingjiang Formation indicate that the area has great exploration potential. To clarify the hydrocarbon migration and accumulation characteristics of the area, the fluid potential of the Longtan Formation in the Qijiang area in the Early Jurassic was determined. The direction of the maximum negative gradient of the fluid potential indicates the direction of the primary migration of hydrocarbons, and the structural ridge theory is used to analyse the direction of the secondary migration of hydrocarbons. The results show that the fluid potential of the hydrocarbon source rocks of the Longtan Formation in the Early Jurassic is characterized by the alternate distribution of high potential zones and low‐potential zones. The central syncline, eastern syncline and western syncline are drainage zones and high potential zones, while the Shiyougou structural belt and Fo'er Ya structural belt are supply zones and low‐potential zones. The oil and gas fluids migrate from the east–west direction to the anticlinal zone for the primary migration; the structural ridge controls the secondary migration of oil and gas in the low‐potential area along the north–south direction, resulting in a zonal distribution of oil and gas traps along the structural ridge. By combining fluid potential and structural ridge characteristics to determine the dominant direction of primary and secondary hydrocarbon migration, a model of hydrocarbon migration and accumulation in the Qijiang area is developed, which provides an important basis for finding hydrocarbon reservoirs.

New understanding and exploration direction of hydrocarbon accumulation in Termit Basin, Niger

Based on the seismic and drilling data, casting thin sections, geochemical analysis of oil and rock samples, and hydrocarbon generation history simulation, the hydrocarbon accumulation characteristics and exploration direction of Termit superimposed marine—continental rift basin are discussed. The Termit basin is superimposed with two-phase rifts (Early Cretaceous and Paleogene). The subsidence curves from two wells on the Trakes slope in the east of the basin show high subsidence rate in the Late Cretaceous, which is believed to be high deposition rate influenced by transgression. However, a weak rift may also be developed. The depositional sequences in the Termit basin were controlled by the Late Cretaceous marine transgression cycle and the Paleogene lacustrine transgression cycle, giving rise to two types of superimposed marine—continental “source-sink” deposits. The marine and continental mixed source rocks developed universally in the whole basinduring the marine transgression period, and are overlaid by the Paleogene Sokor 1 reservoir rocks and Sokor 2 caprocks developed during the lacustrine transgression period, forming the unique superimposed marine—continental basin in WCARS. The early low geothermal gradient in the Termit basin resulted in the late hydrocarbon generated by the source rock of Upper Cretaceous Yogou in Paleogene. Mature source rock of Upper Cretaceous Donga developed in the Trakes slope, so that the double-source-supply hydrocarbon and accumulation models are proposed for the Trakes slope in which formed the oil fields. Due to virtue of the newly proposed hydrocarbon accumulation model and the exploration activities in recent years in the Termit superimposed marine—continental rift basin, an additional effective exploration area of about 2500 km2 has been confirmed in the east of the basin. It is believed that potential domains such as Sokor 1, Donga and Upper Cretaceous lithologic traps in the southeast of the basin are key expected targets for exploration and frontier evaluation in future.

Structural features and exploration targets of platform margins in Sinian Dengying Formation in Deyang—Anyue Rift, Sichuan Basin, SW China

Based on the seismic, logging, drilling and other data, the distribution, structural types and mound-shoal hydrocarbon accumulation characteristics of platform margins of the Sinian Dengying Formation in the Deyang—Anyue Rift and its periphery were analyzed. Four types of platform margins are developed in the Dengying Formation, i.e., single-stage fault-controlled platform margin, multi-stage fault-controlled platform margin, gentle slope platform margin, and overlapping platform margin. In the Gaoshiti West—Weiyuan East area, single-stage fault controlled platform margins are developed in the Deng 2 Member, which trend in nearly NEE direction and are shielded by faults and mudstones, forming fault-controlled—lithologic traps. In the Lezhi—Penglai area, independent and multi-stage fault controlled platform margins are developed in the Deng 2 Member, which trend in NE direction and are controlled by synsedimentary faults; the mound-shoal complexes are aggraded and built on the hanging walls of the faults, and they are shielded by tight intertidal belts and the Lower Cambrian source rocks in multiple directions, forming fault-controlled—lithologic and other composite traps. In the Weiyuan—Ziyang area, gentle slope platform margins are developed in the Deng 2 Member, which trend in NW direction; the mound-shoal complexes are mostly thin interbeds as continuous bands and shielded by tight intertidal belts in the updip direction, forming lithologic traps. In the Gaoshiti—Moxi—Yanting area, overlapping platform margins are developed in the Deng 2 and Deng 4 members; the mound-shoal complexes are aggraded and overlaid to create platform margin buildup with a huge thickness and sealed by tight intertidal belts and the Lower Cambrian mudstones in the updip direction, forming large-scale lithologic traps on the north slope of the Central Sichuan Paleouplift. To summarize, the mound-shoal complexes on the platform margins in the Dengying Formation in the Penglai—Zhongjiang area, Moxi North—Yanting area and Weiyuan—Ziyang area are large in scale, with estimated resources of 1.58×1012 m3, and they will be the key targets for the future exploration of the Dengying Formation in the Sichuan Basin.

Integration of charging time, migration pathways and sealing analysis to understand hydrocarbon accumulation in complex fault blocks, the Pinghu Slope Belt of the Xihu Depression, East China Sea Basin

A large number of oil and gas fields have been successfully discovered in complex fault blocks worldwide. However, the role played by the fault-rock seal in the hanging wall traps is not fully understood due to the paucity of datasets. The trap examples of the Pinghu Slope Belt are used to analyze the migration and accumulation of hydrocarbons in the complex fault blocks, as well as the fault-sealing mechanism of the hanging wall traps. The burial history in typical wells, combined with the homogenization temperature of fluid inclusions, is used to determine the hydrocarbon charging time. Based on detailed 3D seismic interpretation, the paleo-structural features at critical moments and their control on hydrocarbon migration were discussed. Hydrocarbon accumulation characteristics were illustrated based on triangle juxtaposition diagrams. The result shows that there are two hydrocarbon charging episodes in the study area, respectively, 10.6–8.1 Ma and 2.8 Ma-present, with the latter being predominant. This phenomenon that the homogenization temperatures of inclusions are generally higher than the measured formation temperatures at the same depth is attributed to late fluid accumulation and not reaching thermal equilibrium with the reservoir fluids. The analysis of hydrocarbon generation history, trap fixation history and fluid inclusions indicate that the critical moment of the generation-migration-accumulation of most hydrocarbons ranges from 2.8 Ma to the present. Due to the difficulty in effectively recognizing the reflector (the top of the Santan Fm) and the nearly horizontal sediments above T20, the reflector T20 (5 Ma) near the top of the Santan Fm was chosen as an approximate proxy for this critical time (2.8 Ma). The paleo-structures of the Pinghu Slope Belt at 5 Ma are a gentle southeast-dipping slope. Based on the numerical simulation of three different fault scenarios (no faults, closed faults and open faults), wells A-H are located on the preferential migration pathways. Fault seal analysis shows that multiple juxtaposition types on the fault surface and moderate-potential to effective SGR values at the sandstone reservoirs in the middle and lower Pinghu Formation. Lateral and vertical reservoir compartmentalizations are presented in clean sand-sand juxtapositions with low-potential sealing (SGR<20%) in well A. The SGR-buoyancy pressure relationship from hanging wall traps and the global calibration plots from footwall traps have a consistent trend. The fault sealing mechanism of hanging wall traps is similar to that of the footwall traps. Therefore， those global calibration plots can be simultaneously applied to the fault seal evaluation of both hanging wall traps and footwall traps.

Characteristics of orderly hydrocarbon accumulation of deep reservoirs in Kuqa Depression and its exploration implications

The Kuqa depression is an important oil and gas production area in western China, and there are abundant natural gas resources in the deep and ultra‐deep tight reservoirs. In this study, the accumulation law of deep oil and gas in the Kuqa depression has been systematically discussed based on the analysis of geochemical parameters, reservoir fluid inclusions and the recovery of burial‐thermal evolution history in different structural zones. The results show that the lacustrine mudstones of the Triassic Huangshanjie and Upper Jurassic Qiakemake formations in the Kuqa depression are the main oil‐generating source rocks, and the coal‐measure source rocks of the Middle and Lower Jurassic are the main gas‐generating source rocks. The oil and gas in the northern tectonic belt originated from the Huangshanjie and Yangxia formations have the characteristics of ‘lower‐source and upper‐reservoir’ and ‘self‐generation and self‐storage’. The source rocks in the central tectonic belt are of high maturity and mainly generate natural gas, and a small amount of crude oil is derived from mudstones of the Jurassic Qiakemake Formation. The oil and gas in the southern slope belt are mainly derived from the source rocks of the Huangshanjie Formation, followed by the Jurassic source rocks. The ordered accumulation of oil and gas in the Kuqa depression is controlled by the effective spatiotemporal matching of multi‐stage tectonic evolution and hydrocarbon generation evolution of multi‐source rocks. Three spatiotemporal ordered hydrocarbon accumulation series have been proposed: early near‐source accumulation, late far and near‐source accumulation, and late upper‐near source accumulation. The piedmont belt is dominated by the near‐source continuous accumulation mode, the thrust belt is dominated by the ultra‐late upper source accumulation mode, and the slope belt is dominated by the late far‐source accumulation mode. Therefore, future exploration will focus on the tight lithologic reservoirs in the northern piedmont belt, the structural reservoirs in the central structural belt, and the unconformity hidden reservoirs in the southern slope belt.

Structural characteristics and deep-water hydrocarbon accumulation model of the Scotian Basin, Eastern Canada

Commercial hydrocarbon reservoirs have been discovered in shallow-water areas of the Scotian Basin, Eastern Canada. However, knowledge about the structure and hydrocarbon accumulation characteristics of the basin is still insufficient, which constrains the oil and gas exploration in deep-water areas. Based on comprehensive data of magnetic anomalies, seismic survey, and drilling, this study determines the structure characteristics of the Scotian Basin and its hydrocarbon accumulation conditions in deep waters and evaluates the deep-water hydrocarbon exploration potential. The transform faults and basement structures in the northern basin control the sedimentary framework showing thick strata in east and thin strata in west of the basin. The bowl-shaped depression formed by thermal subsidence during the transitional phase and the confined environment (micro basins) caused by salt tectonics provide favorable conditions for the development of source rocks during the depression stage (also referred to as the depression period sequence) of the basin. The progradation of large shelf-margin deltas during the drift phase and steep continental slope provide favorable conditions for the deposition of slope-floor fans on continental margins of the basin. Moreover, the source-reservoir assemblage comprising the source rocks within the depression stage and the turbidite sandstones on the continental margin in the deep waters may form large deep-water turbidite sandstone reservoirs. This study will provide a valuable reference for the deep-water hydrocarbon exploration in the Scotian Basin.

Biomarkers and Carbon Isotope of Monomer Hydrocarbon in Application for Oil-Source Correlation and Migration in the Moxizhuang-Yongjin Block, Junggar Basin, NW China.

Different opinions on the oil-source correlation and migration of the Moxizhuang-Yongjin block in the Junggar Basin, NW China, have seriously affected oil and gas exploration in this area. This research is based on the results of biomarker analysis and carbon isotope of monomer hydrocarbon on crude oil and source rock samples from different blocks. Two oil families (A1, A2, and B) are classified by cluster analysis on nine typical biomarker ratios. Typically, sub-family A1 oils are distributed in the Zhuang 102 well block of the Moxizhuang block, and their gammacerane index is the highest. The abundance of C24 tetracyclic terpanes is the lowest, the C27 regular steranes are dominant, and the organic matter is mainly input by lower aquatic organisms. Sub-family A2 oils are distributed in the Zheng 1-1 well block of the Moxizhuang block. The gammacerane index of oils is lower than the former, and the abundance of C24 tetracyclic terpanes is higher. In the dual input of lower aquatic organisms and terrestrial higher plants, the input of terrestrial higher plants accounted for a larger proportion. Family B oils are distributed in the Yong 2 well block of the Yongjin block, and their gammacerane index is the lowest. They have a high abundance of C24 tetracyclic terpanes, and C29 regular steranes are dominant, reflecting the characteristics of terrigenous organic matter contribution. Based on the biomarker compound composition, at least two oil charges are indicated: Sub-family A1 oils are likely sourced from the Wuerhe formation, sub-family A2 oils may be a mixture of Wuerhe formation and Badaowan formation, and family B oils are likely sourced from the Badaowan formation. The oil families with typical genetic affinities may indicate two major petroleum systems or multiple oil systems existing in the study area. In addition, the characteristics of hydrocarbon accumulation and migration are also discussed, the oil and gas in the West Sag of Well Pen 1 and Changji Sag are filled from deep to shallow in the vertical direction and migrated from south to north in the horizontal direction, at the same time, with the help of sand bodies and faults, and they migrated to the north and northeast. This work provides a scientific basis for oil and gas exploration in the hinterland of the Junggar Basin.

Constraining hydrocarbon migration and accumulation by two-dimensional numerical simulation: Ordovician carbonate reservoirs of the Daniudi Area, Ordos Basin

The various types of reservoir space in carbonate reservoirs make the process of hydrocarbon migration and accumulation very complex. How to quantitatively characterize the characteristics of hydrocarbon migration and accumulation in carbonate reservoirs is one of the key problems for carbonate hydrocarbons exploration and exploitation. Taking the Ordovician in the Daniudi area of Ordos Basin as an example, three types of source rock-reservoir-cap assemblages, namely upper-generation assemblage, lateral variable assemblage, and self-generation-reservoir-cap assemblage, were determined by characterizing the forming elements of carbonate reservoirs. Petromod software is used to build a two-dimensional profile model, and vitrinite reflectance of source rock and porosity of the reservoir were used as correction parameters, and the hydrocarbon migration and accumulation process was simulated by the invasion percolation algorithm. It is confirmed that the Ordovician Majiagou formation in the study area has three periods of hydrocarbon charging and three periods of hydrocarbon adjustment. The hydrocarbon migration pathways in carbonate rocks include lateral contact in the pinch-out area, source rock-reservoir contact in the trough area, fault-connected, and source rock-reservoir superposition. The source rock-reservoir-cap assemblages of upper-generation assemblage and lateral variable assemblage correspond to the lateral contact in the pinch-out area, source rock-reservoir contact in the trough area, fault-connected, while self-generation-reservoir-cap assemblage corresponds to the fault-connected, and source rock-reservoir superposition. The high part of the structure and fault zone are the strongest structural deformation parts, whose fractures are relatively developed, controlling the location of hydrocarbon accumulation, meanwhile, the reservoir quality directly controls the degree of hydrocarbons saturation. The research results are beneficial to establish a more accurate quantitative evaluation method of hydrocarbon migration and accumulation in carbonate rocks and to understanding the controlling factors of hydrocarbon migration and accumulation in carbonate rocks.

Classification of Typical Tectonic Styles and Exploration of Hydrocarbon Accumulation Patterns in Southern Junggar Basin, China

Affected by Tianshan uplift, the southern Junggar Basin has experienced multi-stage tectonic movements and formed many large-scale anticlines with zonal distribution. The key to hydrocarbon exploration is to accurately implement anticline traps. This paper is guided by the fault-related folds theory to tectonically interpret several seismic profiles in the southern Junggar Basin and then summarize the anticline types and their hydrocarbon accumulation characteristics. This paper showed that the southern Junggar Basin has a tectonic assemblage pattern of “multi-detachment layers and multi-phase superposition”. According to the superimposed shape of the anticlines, they could be divided into overthrust anticlines, compound anticlines and multiple superimposed anticlines, and the horizontal and vertical positions of the different types of anticlines are different. The hydrocarbon accumulating characteristics of the different types of anticlines are shown to be different. The highs of the overthrust anticlines and compound anticlines are stable, and the degree of exploration is relatively high. Although the degree of exploration of multiple overlapping anticlines is low, multiple layers can be exploited simultaneously in the process of oil development, with great hydrocarbon potential. The characteristics of hydrocarbon accumulation in the southern Junggar Basin are discussed in order to provide guidance for efficient hydrocarbon exploration.

Geochemical characteristics of crude oils and hydrocarbon accumulation in the Palogue Oilfield, Melut Basin, South Sudan

The Palogue Oilfield is the largest oilfield in the Melut Basin, an important petroliferous rift basin in Africa. Geochemical analyses, including gas chromatography and gas-mass chromatography were adopted to analyze the biomarker composition and geochemical characteristics of oils from the Palogue Oilfield and the neighboring Moleeta and Jamous lows. Oil-oil correlations were performed for the Palogue Oilfield and the Moleeta/Jamous lows, and the hydrocarbon accumulations of the Palogue Oilfield were studied based on the oil maturities, thermal evolution modelling of the Moleeta/Jamous lows and the petroleum system analysis of the Melut Basin. Geochemical analysis indicates that the oils of the Moleeta/Jamous lows are derived from terrestrial higher plants, with the low ratios (<1) of light n-alkanes to heavy n-alkanes (∑nC21-/∑nC22+) and the predominance of C29 regular sterane, but there still are some geochemical differences in distribution shape of n-alkanes, paleoenvironments and maturities in these two lows. The oils of the Palogue Oilfield have mixed-source features and their geochemical characteristics are more like those of the Jamous low, and a few oils are like the oils in the Moleeta low. The Jamous low has a larger area and higher thermal maturity than the Moleeta low, and the abundant oils generated by the Al Renk source rocks (upper part of early Cretaceous) in the Jamous low are the primary contributors to the formation of the giant Palogue Oilfield. The vitrinite reflectance equivalent (Rc) converted by the methyl phenanthrene ratio indicates that the oil maturities of the Palogue Oilfield range from 0.65% to 1.07%. Thermal evolution modelling of the Moleeta/Jamous lows indicates that the Jamous low generated and expelled hydrocarbons earlier than the Moleeta low. The maturity of Al Renk source rocks reached 0.65% at 70Ma (Late Cretaceous) and 1.07% at 38Ma (Eocene) in the Jamous low, and reached 0.65% at 59Ma (Paleocene) and 1.07% at present in the Moleeta low. Thus, the high-maturity oils (Ro> 1.07%) generated by the source rocks in the Jamous low since 38 Ma have not been discovered in the primary production layers of the Paleogene Samma and Yabus Formations in the higher part of the Palogue structure, a drape-anticline developing on a paleo-high between the Jamous and Moleeta lows. The maturity parameter of Ts/(Ts + Tm) shows that the oil maturities from late Cretaceous Formation in the well PS-7 and PS-8 are close to the oils in the Jamous Low and are significantly higher than the oils from the Paleogene Formation in the higher part of the Palogue structure. So, the Cretaceous Formation under the Paleogene pay zones and the Paleogene Formation in the lower part of the Palogue structure likely accumulated high-maturity oils from the Jamous low, which will enhance the exploration potential of the Palogue Oilfield. The petroleum system study indicates that the end of Oligocene (late Paleogene) is the critical moment for the Paleogene hydrocarbon accumulations in the Melut Basin. Whereas, the high-maturity oil accumulations (Ro> 1.07%) in Cretaceous formations in the Palogue Oilfield occurred after 38Ma (late Eocene), when the Al Renk source rocks in the Jamous low started to enter the high thermal evolution stage with the Ro> 1.07%.

Exploration discovery and hydrocarbon accumulation characteristics of the Doseo strike-slip and inverted basin, Chad

Several international oil companies had conducted petroleum exploration, but failed to make any commercially viable discoveries in the Doseo Basin for over 30 years. In this article, an integrated analysis, based on the latest seismic and drilling data combined with exploration practice and tectonic, sedimentary as well as petroleum-geological characteristics of the basin, has been conducted with the aim to disclose the key factors of hydrocarbon accumulation and enrichment and then to find the potential petroleum plays. The Doseo Basin in Chad is a Meso-Cenozoic lacustrine rift basin developed on the Precambrian crystalline basement in the Central African Shear Zone. It is a half graben rift controlled by the strike-slip fault at the northern boundary, and can be divided into two sub-basins, an uplift and a slope. The basin experienced two rifting periods in the Cretaceous and was strongly inverted with the erosion thickness of 800–1000 m during the Eocene, and then entered the depression and extinction period. Structurally, a large number of normal faults and strike-slip faults are identified in the basin, and the boundary faults are inverted faults with normal at first. The main structural styles include inverted anticlines, fault noses, complex fault-blocks and flower structures. The Lower Cretaceous is the main sedimentary strata, which are divided into the Mangara Group, Kedeni, Doba and Koumra Formations from bottom to up. Two transgressive-regressive cycles developed in the Lower Cretaceous indicates with mainly lacustrine, fluvial, delta, braided-delta, fan-delta sandstone and mudstone. The effective source rock in the basin is the deep-lacustrine mudstone of the Lower Cretaceous containing the type I and type II1 organic matters. Furthermore, Inverted anticlines and fault-complicated blocks comprise the main trap types and the Kedeni Uplift is the most favorable play, followed by the Northern Steep Slope and Southern Gentle Slope. Lateral sealing capacity of faults controls the hydrocarbon abundance.

Characteristics of fluid potential and the division of hydrocarbon migration and accumulation units in the Nangong Sag, Bohai Bay Basin, China

The oil-gas display of early drilling suggests a considerable exploration prospect in the Nangong Sag. Previous researchers have not analyzed the characteristics of hydrocarbon migration and accumulation from the perspective of fluid potential. We use the Hubbert flow potential model to restore the flow potential of the Nangong Sag in the Pliocene, which was a key period of hydrocarbon generation. The results show that the high value area of fluid potential is large and mainly located in the southeastern part of the study area. The southeast subsag provided fluid, and the northwest slope accumulated fluid. The fluid potential gradual decrease from the southeast subsag to the northwest slope. According to the division trough theory, the Nangong Sag is divided into 8 hydrocarbon migration and accumulation units. We suggest that migration and accumulation units III, IV and V are favorable areas for hydrocarbon exploration. The study area has favorable source-reservoir-cap, pool-forming conditions and good time allocation relationship of hydrocarbon. Based on the characteristics of fluid potential, the hydrocarbon generation and accumulation modes of migration and accumulation unit III and IV in Nangong Sag are preliminarily put forward. The research results have guiding significance for future hydrocarbon exploration in the study area.